Systems and Methods for Draw Down Improvement in Wellbores

ABSTRACT

A method for determining an operating envelope for a wellbore includes receiving an indication of sand ingress into the wellbore from at least one production zone, sand transport along the wellbore, or both while producing one or more fluids from the wellbore from the at least one production zone, correlating a force on a production face of the at least one production zone of the wellbore with the sand ingress, the sand transport, or both, and determining an operating envelope based on the correlating. The operating envelope defines a boundary for the force on the production face of the at least one production zone of the wellbore during a production of the one or more fluids from the at least one production zone.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of and priority to InternationalApplication No. PCT/EP2019/075385 filed Sep. 20, 2019 with the EPOReceiving Office and entitled “Systems and Methods for Draw DownImprovement in Wellbores,” which is hereby incorporated herein byreference in its entirety for all purposes.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

BACKGROUND

To obtain hydrocarbons from subterranean formations, wellbores aredrilled from the surface to access the hydrocarbon-bearing formation.After drilling a wellbore to the desired depth, a production string isinstalled in the wellbore to produce the hydrocarbons from one or moreproduction zones of the formation to the surface. In some wellbores,fine particulate matter (which is generally referred to herein as“sand”) may be produced along with other fluids (e.g., hydrocarbonliquids, gas, water, etc.). The sand may cause plugging and erosion orwear within the well. Thus, it is desirable to prevent sand fromadvancing into the wellbore (e.g., with a screen or other suitabledevice or completion method), or to minimize (or prevent entirely) theproduction of sand from the subterranean formation.

BRIEF SUMMARY

In an embodiment, a method for determining an operating envelope for awellbore comprises: receiving an indication of sand ingress into thewellbore from at least one production zone, sand transport along thewellbore, or both while producing one or more fluids from the wellborefrom the at least one production zone, correlating a force on aproduction face of the at least one production zone of the wellbore withthe sand ingress, the sand transport, or both, and determining anoperating envelope based on the correlating. The operating envelopedefines a boundary for the force on the production face of the at leastone production zone of the wellbore during a production of the one ormore fluids from the at least one production zone.

In an embodiment, a system for determining an operating envelope for awellbore comprises a monitoring assembly configured to detect one ormore values related to the wellbore, a processor. The processor isconfigured to execute an analysis program to: receive, from themonitoring assembly, a sensor signal, wherein the sensor signal isgenerated while producing one or more fluids from at least oneproduction zone within the wellbore, receiving an indication of sandingress into the wellbore, sand transport along the wellbore, or bothusing the sensor signal, correlate a force on a production face of theat least one production zone of the wellbore with the sand ingress, thesand transport, or both, and determine an operating envelope based onthe correlating. The operating envelope defines a boundary for the forceon the production face of the at least one production zone during aproduction of the one or more fluids from the at least one productionzone.

In an embodiment, a method of controlling a drawdown pressure in awellbore comprises: producing one or more fluids from a wellbore at afirst production rate, increasing a production of the one or more fluidsfrom the first production rate to a second production rate, and limitingsand ingress into the wellbore during the pressure increase based onmaintaining the rate of pressure change within the operating envelope.The first production rate is less than the second production rate, andthe production rate increase is maintained within an operating envelope.The operating envelope defines a boundary for a rate of pressure changeduring a production of the one or more fluids from the wellbore.

Embodiments described herein comprise a combination of features andcharacteristics intended to address various shortcomings associated withcertain prior devices, systems, and methods. The foregoing has outlinedrather broadly the features and technical characteristics of thedisclosed embodiments in order that the detailed description thatfollows may be better understood. The various characteristics andfeatures described above, as well as others, will be readily apparent tothose skilled in the art upon reading the following detaileddescription, and by referring to the accompanying drawings. It should beappreciated that the conception and the specific embodiments disclosedmay be readily utilized as a basis for modifying or designing otherstructures for carrying out the same purposes as the disclosedembodiments. It should also be realized that such equivalentconstructions do not depart from the spirit and scope of the principlesdisclosed herein.

BRIEF DESCRIPTION OF THE DRAWINGS

For a detailed description of various exemplary embodiments, referencewill now be made to the accompanying drawings in which:

FIG. 1 is a schematic, cross-sectional illustration of a downholewellbore environment according to some embodiments;

FIGS. 2A and 2B are a schematic, cross-sectional views of embodiments ofa well with a wellbore tubular having an optical fiber inserted thereinaccording to some embodiments;

FIG. 3 is a schematic view of an embodiment of a wellbore tubular withfluid inflow and sand ingress according to some embodiments;

FIG. 4 is a flow diagram of a method of determining an operatingenvelope for a wellbore according to some embodiments;

FIG. 5 is a flow diagram of a method of determining an operatingenvelope for a second wellbore, based on predetermined operatingenvelopes from one or more first wellbores according to someembodiments;

FIG. 6 is a flow diagram of a method of completing a wellbore accordingto some embodiments; and

FIG. 7 schematically illustrates a computer that may be used to carryout various methods according to some embodiments.

DETAILED DESCRIPTION

The following discussion is directed to various exemplary embodiments.However, one of ordinary skill in the art will understand that theexamples disclosed herein have broad application, and that thediscussion of any embodiment is meant only to be exemplary of thatembodiment, and not intended to suggest that the scope of thedisclosure, including the claims, is limited to that embodiment.

The drawing figures are not necessarily to scale. Certain features andcomponents herein may be shown exaggerated in scale or in somewhatschematic form and some details of conventional elements may not beshown in interest of clarity and conciseness.

Unless otherwise specified, any use of any form of the terms “connect,”“engage,” “couple,” “attach,” or any other term describing aninteraction between elements is not meant to limit the interaction todirect interaction between the elements and may also include indirectinteraction between the elements described. In the following discussionand in the claims, the terms “including” and “comprising” are used in anopen-ended fashion, and thus should be interpreted to mean “including,but not limited to . . . ”. Reference to up or down will be made forpurposes of description with “up,” “upper,” “upward,” “upstream,” or“above” meaning toward the surface of the wellbore and with “down,”“lower,” “downward,” “downstream,” or “below” meaning toward theterminal end of the well, regardless of the wellbore orientation.Reference to inner or outer will be made for purposes of descriptionwith “in,” “inner,” or “inward” meaning towards the central longitudinalaxis of the wellbore and/or wellbore tubular, and “out,” “outer,” or“outward” meaning towards the wellbore wall. As used herein, the term“longitudinal” or “longitudinally” refers to an axis substantiallyaligned with the central axis of the wellbore tubular, and “radial” or“radially” refer to a direction perpendicular to the longitudinal axis.The various characteristics mentioned above, as well as other featuresand characteristics described in more detail below, will be readilyapparent to those skilled in the art with the aid of this disclosureupon reading the following detailed description of the embodiments, andby referring to the accompanying drawings.

As utilized herein, a ‘fluid inflow event’ includes fluid inflow (e.g.,any fluid inflow regardless of composition thereof), gas phase inflow,aqueous phase inflow, and/or hydrocarbon phase inflow. The fluid cancomprise other components such as solid particulate matter in someembodiments, as discussed in more detail herein.

As previously described, sand may be produced from one or moreproduction zones of a subterranean reservoir along with other fluidsthrough a hydrocarbon producing wellbore, and the produced sand may leadto a host of problems and complications. As a result, it may bedesirable to limit or prevent the production of sand during operations.

One method of limiting or reducing sand production from a wellbore (or aproduction zone within a wellbore), may be to manipulate a drawdownpressure within the wellbore. As used herein, the term “drawdownpressure” refers to the pressure differential between the pressure of asubterranean formation and the pressure of a wellbore extending throughthe formation (this is sometimes also referred to as the “pressuredrawdown”). To allow production fluids to enter the wellbore forproduction to the surface, the drawdown pressure is set such that thepressure within the wellbore is generally less than the pressure of theformation. Thus, the drawdown pressure drives formation fluids from thesubterranean formation into the wellbore during production operations,and one would normally expect the drawdown pressure to be proportional(or at least related to) to the flow rate of production fluids into thewellbore. Accordingly, as the drawdown pressure increases (i.e., thepressure differential between the formation and wellbore increases) theflow rate of formation fluids into the wellbore from the formationshould also increase. As described herein, the drawdown pressure may beinfluenced or managed by the actuation of choke valves or other pressureadjustment devices (e.g., pumps, valves, etc.).

In some circumstances, a rate of sand production may be influenced byadjusting the drawdown pressure within the wellbore during operations.For instance, one might lower a drawdown pressure so as to limit or atleast reduce the sand production rate into a given wellbore. Inaddition, the rate of change for the pressure drawdown may also affect arate of sand production during operations. Specifically, if a drawdownpressure is changed relatively rapidly (e.g., increased), then a forceon the production face of one or more production zones within thewellbore may increase such that sand is more readily mobilized andflowed into the wellbore along with other production fluids (e.g., oil,gas, water, etc.). This effect can be thought of as shocking theformation and thereby releasing sand into the wellbore. The force on theproduction face of a wellbore may be measured or characterized by one ormore of a rate of pressure change in the production zone, a flux of theone or more fluids through the production face of the wellbore, or anacceleration of the one or more fluids between a reservoir and aninterior of the wellbore at the production face of the wellbore. Thus,as used herein, the “force on the production face” of a production zoneof a wellbore may refer to any of these above-listed parameters. Inaddition, as will be described in more detail below some or all of theseparameters characterizing the force on the production face may beinfluenced or may directly result from the drawdown pressure (andspecifically changes in the drawdown pressure) during productionoperations. Accordingly, in at least some of the embodiments describedherein, the force on the production face of a production zone of awellbore may be assessed and monitored via one or more pressuremeasurements (e.g., a wellbore pressure, drawdown pressure, formationpressure, etc.).

Thus, precise and timely control of the drawdown pressure (e.g., via achoke or other suitable pressure adjustment devices as previouslydescribed above) may be called for to prevent or at least minimize arate of sand ingress into a subterranean wellbore so as to avoid theabove-described difficulties and failures. However, it can be difficultto precisely determine how to adjust a drawdown pressure to limit sandproduction while still maintaining an acceptable flow of hydrocarbonfluids. Specifically, in many circumstances, a wellbore operator maydetermine a rate of sand production based on an amount of sand that isproduced at the surface. However, the sand produced at the surface doesnot always accurately correlate with an actual ingress rate of sand fromthe formation into the wellbore. For instance, sand that is producedfrom a formation may accumulate within the wellbore, and subsequentproduction of sand may simply correspond with a flowing of previouslyproduced and accumulated sand out of the wellbore. Thus, an operator maycorrelate a current drawdown pressure (or recent drawdown pressurechange) with observed surface sand production that may not actuallydirectly result from formation sand production. Further, a delay isintroduced between the time the sand is produced from the formation andthe time the sand is observed on the surface based on a fluid flow rate,which can make a correlation between the drawdown pressure and the sandproduction rate when the drawdown pressure is being changed. As aresult, in an effort to limit perceived sand ingress, a wellboreoperator may overly reduce the drawdown pressure so that production fromthe wellbore is substantially reduced or substantially eliminated, ormay overly increase drawdown pressure so that sand ingress is increased.

Accordingly, embodiments disclosed herein include systems and methodsfor detecting and/or characterizing sand ingress and/or sand flow withina subterranean wellbore, so that a wellbore operator may moreeffectively prevent or minimize sand production into the wellbore duringoperations. In some embodiments, utilizing the systems and methodsdescribed herein, an operating envelope may be developed to defineoperating parameters of the wellbore (e.g., a rate of pressure change inthe production zone, a flux of the one or more fluids through theproduction face of the wellbore, or an acceleration of the one or morefluids between a reservoir and an interior of the wellbore at theproduction face of the wellbore, etc.) so as to limit or even avoid sandingress during operations. In some embodiments, a distributed acousticsensor (DAS) may be utilized to detect the sand ingress, and/or sandtransport within a wellbore. In some embodiments, the determinedoperating envelope may be applied to one or more production zones in thesame or other wellbores that have corresponding geophysical properties.In some embodiments, the sand ingress predictions can be used across orbetween reservoirs to enable production control (e.g., production ratecontrol with an appropriate sand control, etc.) for wellbores that havenot previously been monitored. In some embodiments, a sand ingresslocation, timing, and/or amount may be predicted so as to inform aproduction, completion, and/or drilling plan for a wellbore (e.g., suchas an existing wellbore or a planned wellbore yet to be drilled and/orcompleted).

Referring now to FIG. 1, where a schematic, cross-sectional illustrationof a downhole wellbore operating environment 101 according to someembodiments is shown. More specifically, environment 101 includes awellbore 114 traversing a subterranean formation 102, casing 112 liningat least a portion of wellbore 114, and a tubular 120 extending throughwellbore 114 and casing 112. A plurality of completion assemblies suchas spaced screen elements or assemblies 118 may be provided alongtubular 120 at one or more production zones 104 a, 104 b within thesubterranean formation 102. In particular, two production zones 104 a,104 b are depicted within subterranean formation 102 of FIG. 1; however,the precise number and spacing of the production zones 104 a, 104 b maybe varied in different embodiments. The production zones 104 a, 104 bmay be layers, zones, or strata of formation 102 that containhydrocarbon fluids (e.g., oil, gas, condensate, etc.) therein.

In addition, a plurality of spaced zonal isolation devices 117 andgravel packs 122 may be provided between tubular 120 and the sidewall ofwellbore 114 at or along the interface of the wellbore 114 with theproduction zones 104 a, 104 b. In some embodiments, the operatingenvironment 101 includes a workover and/or drilling rig positioned atthe surface and extending over the wellbore 114. While FIG. 1 shows anexample completion configuration in FIG. 1, it should be appreciatedthat other configurations and equipment may be present in place of or inaddition to the illustrated configurations and equipment.

In general, the wellbore 114 can be formed in the subterranean formation102 using any suitable technique (e.g., drilling). The wellbore 114 canextend substantially vertically from the earth's surface over a verticalwellbore portion, deviate from vertical relative to the earth's surfaceover a deviated wellbore portion, and/or transition to a horizontalwellbore portion. In general, all or portions of a wellbore may bevertical, deviated at any suitable angle, horizontal, and/or curved. Inaddition, the wellbore 114 can be a new wellbore, an existing wellbore,a straight wellbore, an extended reach wellbore, a sidetracked wellbore,a multi-lateral wellbore, and other types of wellbores for drilling andcompleting one or more production zones. As illustrated, the wellbore114 includes a substantially vertical producing section 150 whichincludes the production zones 104 a, 104 b. In this embodiment,producing section 150 is an open-hole completion (i.e., casing 112 doesnot extend through producing section 150). Although section 150 isillustrated as a vertical and open-hole portion of wellbore 114 in FIG.1, embodiments disclosed herein can be employed in sections of wellboreshaving any orientation, and in open or cased sections of wellbores. Thecasing 112 extends into the wellbore 114 from the surface and can besecured within the wellbore 114 with cement 111.

The tubular 120 may comprise any suitable downhole tubular or tubularstring (e.g., drill string, casing, liner, jointed tubing, and/or coiledtubing, etc.), and may be inserted within wellbore 114 for any suitableoperation(s) (e.g., drilling, completion, intervention, workover,treatment, production, etc.). In the embodiment shown in FIG. 2, thetubular 120 is a completion assembly string. In addition, the tubular120 may be disposed within in any or all portions of the wellbore 114(e.g., vertical, deviated, horizontal, and/or curved section of wellbore114).

In this embodiment, the tubular 120 extends from the surface to theproduction zones 104 a, 104 b and generally provides a conduit forfluids to travel from the formation 102 (particularly from productionzones 104 a, 104 b) to the surface. A completion assembly including thetubular 120 can include a variety of other equipment or downhole toolsto facilitate the production of the formation fluids from the productionzones. For example, zonal isolation devices 117 can be used to isolatethe production zones 104 a, 104 b within the wellbore 114. In thisembodiment, each zonal isolation device 117 comprises a packer (e.g.,production packer, gravel pack packer, frac-pac packer, etc.). The zonalisolation devices 117 can be positioned between the screen assemblies118, for example, to isolate different gravel pack zones or intervalsalong the wellbore 114 from each other. In general, the space betweeneach pair of adjacent zonal isolation devices 117 defines a productioninterval, and each production interval may corresponding with one of theproduction zones 104 a, 104 b of subterranean formation 102.

The screen assemblies 118 provide sand control capability. Inparticular, the sand control screen elements 118, or other filter mediaassociated with wellbore tubular 120, can be designed to allow fluids toflow therethrough but restrict and/or prevent particulate matter ofsufficient size from flowing therethrough. The screen assemblies 118 canbe of the type known as “wire-wrapped”, which are made up of a wireclosely wrapped helically about a wellbore tubular, with a spacingbetween the wire wraps being chosen to allow fluid flow through thefilter media while keeping particulates that are greater than a selectedsize from passing between the wire wraps. Other types of filter mediacan also be provided along the tubular 120 and can include any type ofstructures commonly used in gravel pack well completions, which permitthe flow of fluids through the filter or screen while restricting and/orblocking the flow of particulates (e.g. other commercially-availablescreens, slotted or perforated liners or pipes; sintered-metal screens;sintered-sized, mesh screens; screened pipes; prepacked screens and/orliners; or combinations thereof). A protective outer shroud having aplurality of perforations therethrough may be positioned around theexterior of any such filter medium.

The gravel packs 122 are formed in the annulus 119 between the screenelements 118 (or tubular 120) and the sidewall of the wellbore 114 in anopen hole completion. In general, the gravel packs 122 compriserelatively coarse granular material placed in the annulus to form arough screen against the ingress of sand into the wellbore while alsosupporting the wellbore wall. The gravel pack 122 is optional and maynot be present in all completions.

In some embodiments, one or more of the completion assemblies cancomprise flow control elements such as sliding sleeves, chokes, valves,or other types of flow control devices that can control the flow of afluid from an individual production zone or a group of production zones.The force on the production face can then vary based on the type ofcompletion within the wellbore and/or each production zone (e.g., in asliding sleeve completion, open hole completion, gravel pack completion,etc.). In some embodiments, a sliding sleeve or other flow controlledproduction zone can experience a force on the production face the isrelatively uniform within the production zone, and the force on theproduction face can be different between each production zone. Forexample, a first production zone can have a specific flow controlsetting that allows the pressure and rate of change of pressure withinthe first zone to be different than a second production zone. Thus, thechoice of completion type (e.g., which can be specified in a completionplan) can depend on the need for or the ability to provide a differentforce on the production face within different production zones. This canallow for improved production using the processes described herein atone or more production zones within the wellbore.

A pressure monitoring system 130 may be installed (e.g., partiallyinstalled) within wellbore 114. Pressure monitoring system 130 mayinclude one (or a plurality of) pressure sensors 132 disposed in variouslocations within wellbore 114 and configured to measure or detect apressure therein. For instance, in some embodiments, pressure monitoringsystems 130 may comprise a plurality of distributed pressure sensorswithin the wellbore 114 (e.g., sensors similar to pressure sensor 132).In some embodiments, the pressure sensors may comprise a fiber opticbased distributed pressure sensor or sensors capable of determining thepressure within one or more locations (e.g., one or more productionzones, etc.) within the wellbore. In some embodiments, a pressure sensorof the pressure monitoring system 130 (e.g., pressure sensor 132) may beconfigured to measure or detect one or more of a pressure of theformation (e.g., such as a pressure of the production zones 104 a, 104b, etc.), a pressure of production tubing (e.g., production tubing 120),or a pressure within the gravel pack 122, etc. As will be described inmore detail below, in some embodiments, pressure monitoring system 130may be used to determine a drawdown pressure of the wellbore (which isdefined above). In addition, the pressure measurements from the pressuremonitoring system 130 may be used to determine, infer, estimate, etc.one or more of the above described parameters that characterize theforce on the production face of a production zone (e.g., productionzones 104 a, 104 b) of the wellbore 114.

Referring still to FIG. 1, a DAS system 110 can be coupled to tubular120. As described herein, DAS system 110 may be utilized to detect ormonitor sand ingress and/or sand transport within the wellbore 114.While described with respect to a DAS system, other monitoring systems(e.g., acoustic monitoring systems whether or not based on fiber opticsensors) including any point or distributed downhole monitoring systemscan also be used within the wellbore, as described in more detailherein. The various monitoring systems (e.g., acoustic monitoringsystems) may be referred to herein as a “sand detection system,” and/ora “sand monitoring system.”

DAS system 110 comprises an optical fiber 162 that is coupled to andextends along tubular 120. In cased completions, the optical fiber 162can be installed between the casing and the wellbore wall within acement layer and/or installed within the casing or production tubing.Referring briefly to FIGS. 2A and 2B, optical fiber 162 of DAS system110 may be coupled to an exterior of tubular 120 (e.g., such as shown inFIG. 2B) or an interior of tubular (e.g., such as shown in FIG. 2A).When the optical fiber 162 is coupled to the exterior of the tubular120, as depicted in the embodiment of FIG. 2B, the optical fiber 162 canbe positioned within a control line, control channel, or recess in thetubular 120. In some embodiments an outer shroud contains the tubular120 and protects the optical fiber 162 during installation. A controlline or channel can be formed in the shroud and the optical fiber 162can be placed in the control line or channel (not specifically shown inFIGS. 2A and 2B).

Referring again to FIG. 1, generally speaking, during operations anoptical backscatter component of light injected into the optical fiber162 may be used to detect acoustic perturbations (e.g., dynamic strain)along the length of the fiber 162. The light can be generated by a lightgenerator or source 166 such as a laser, which can generate lightpulses. The light used in the system is not limited to the visiblespectrum, and light of any frequency can be used with the systemsdescribed herein. Accordingly, the optical fiber 162 acts as the sensorelement with no additional transducers in the optical path, andmeasurements can be taken along the length of the entire optical fiber162. The measurements can then be detected by an optical receiver suchas sensor 164 and selectively filtered to obtain measurements from agiven depth point or range, thereby providing for a distributedmeasurement that has selective data for a plurality of zones (e.g.,production zones 104 a, 104 b) along the optical fiber 162 at any giventime. For example, time of flight measurements of the backscatteredlight can be used to identify individual zones or measurement lengths ofthe fiber optic 162. In this manner, the optical fiber 162 effectivelyfunctions as a distributed array of microphones spread over the entirelength of the optical fiber 162, which typically across production zones104 a, 104 b within the wellbore 114, to detect downhole acousticsignals.

The light backscattered up the optical fiber 162 as a result of theoptical backscatter can travel back to the source, where the signal canbe collected by a sensor 164 and processed (e.g., using a processor168). In general, the time the light takes to return to the collectionpoint is proportional to the distance traveled along the optical fiber162, thereby allowing time of flight measurements of distance along theoptical fiber. The resulting backscattered light arising along thelength of the optical fiber 162 can be used to characterize theenvironment around the optical fiber 162. The use of a controlled lightsource 166 (e.g., having a controlled spectral width and frequency) mayallow the backscatter to be collected and any disturbances along thelength of the optical fiber 162 to be analyzed. In general, any acousticor dynamic strain disturbances along the length of the optical fiber 162can result in a change in the properties of the backscattered light,allowing for a distributed measurement of both the acoustic magnitude(e.g., amplitude), frequency and, in some cases, of the relative phaseof the disturbance. Any suitable detection methods including the use ofhighly coherent light beams, compensating interferometers, localoscillators, and the like can be used to produce one or more signalsthat can be processed to determine the acoustic signals or strainimpacting the optical fiber along its length.

An acquisition device 160 may be coupled to one end of the optical fiber162 that comprises the sensor 164, light generator 166, a processor 168,and a memory 170. As discussed herein, the light source 166 can generatethe light (e.g., one or more light pulses), and the sensor 164 cancollect and analyze the backscattered light returning up the opticalfiber 162. In some contexts, the acquisition device 160 (which comprisesthe light source 166 and the sensor 164 as noted above), can be referredto as an interrogator. The processor 168 may be in signal communicationwith the sensor 164 and may perform various analysis steps described inmore detail herein. While shown as being within the acquisition device160, the processor 168 can also be located outside of the acquisitiondevice 160 including being located remotely from the acquisition device160. The sensor 164 can be used to obtain data at various rates and mayobtain data at a sufficient rate to detect the acoustic signals ofinterest with sufficient bandwidth. While described as a sensor 164 in asingular sense, the sensor 164 can comprise one or more photodetectorsor other sensors that can allow one or more light beams and/orbackscattered light to be detected for further processing. In anembodiment, depth resolution ranges in a range of from about 1 meter toabout 10 meters, or less than or equal to about 10, 9, 8, 7, 6, 5, 4, 3,2, or 1 meter can be achieved. Depending on the resolution needed,larger averages or ranges can be used for computing purposes. When ahigh depth resolution is not needed, a system may have a widerresolution (e.g., which may be less expensive) can also be used in someembodiments. Data acquired by the DAS system 110 (e.g., via fiber 162,sensor 164, etc.) may be stored on memory 170.

While the system 101 described herein can be used with a DAS system(e.g., DAS system 110) to acquire an acoustic signal for a location ordepth range in the wellbore 114, in general, any suitable acousticsignal acquisition system can be used in performing embodiments ofmethod 10 (see e.g., FIG. 1). For example, various microphones,geophones, hydrophones, or other sensors can be used to provide anacoustic signal at a given location based on the acoustic signalprocessing described herein. Further, an optical fiber comprising aplurality of point sensors such as Bragg gratings can also be used. Asdescribed herein, a benefit of the use of the DAS system 110 is that anacoustic signal can be obtained across a plurality of locations and/oracross a continuous length of the wellbore 114 rather than at discretelocations.

During operations, the fluid flowing into the tubular 120 may comprisehydrocarbon fluids, such as, for instance hydrocarbon liquids (e.g.,oil) or gases (e.g., natural gas such as methane, ethane, etc.).However, the fluid flowing into the tubular may also comprise othercomponents, such as, for instance water, steam, carbon dioxide, and/orvarious multiphase mixed flows. In addition, as previously mentionedabove, in some embodiments, the fluid flowing into the tubular 120 mayalso include sand. The fluid flow can further be time varying such asincluding slugging, bubbling, or time altering flow rates of differentphases. The amounts or flow rates of these components can vary over timebased on conditions within the formation 102 and the wellbore 114.Likewise, the composition of the fluid flowing into the tubular 120sections throughout the length of the entire production string (e.g.,including the amount of sand contained within the fluid flow) can varysignificantly from section to section at any given time.

Fluid can be produced into the wellbore 114 and into the completionassembly string. As the fluid enters the wellbore 114, it may createacoustic sounds that can be detected using an acoustic sensor such as aDAS system (e.g., fiber 162). Accordingly, the flow of the variousfluids into the wellbore 114 and/or through the wellbore 114 can createvibrations or acoustic sounds that can be detected using DAS system 110.Each type of event such as the different fluid flows and fluid flowlocations can produce an acoustic signature with unique frequency domainfeatures.

As used herein, various frequency domain features can be obtained fromthe acoustic signal, and in some contexts, the frequency domain featurescan also be referred to herein as spectral features or spectraldescriptors. The frequency domain features are features obtained fromthe frequency domain analysis of the acoustic signals obtained withinthe wellbore. The frequency domain features can be derived from the fullspectrum of the frequency domain of the acoustic signal such that eachof the frequency domain features can be representative of the frequencyspectrum of the acoustic signal. Further, a plurality of differentfrequency domain features can be obtained from the same acoustic signal,where each of the different frequency domain features is representativeof frequencies across the same frequency spectrum of the acoustic signalas the other frequency domain features. For example, the frequencydomain features (e.g., each frequency domain feature) can be statisticalshape measurement or spectral shape function of the spectral powermeasurement across the same frequency bandwidth of the acoustic signal.Further, as used herein, frequency domain features can also refer tofeatures or feature sets derived from one or more frequency domainfeatures, including combinations of features, mathematical modificationsto the one or more frequency domain features, rates of change of the oneor more frequency domain features, and the like.

Specific spectral signatures can be determined for each event byconsidering one or more frequency domain features of the acoustic signalobtained from the wellbore. More specifically, each event can have acharacteristic set of frequency domain features, or combinations thereof(e.g., an acoustic or spectral signature), that fall within certainthresholds as defining the event. The resulting spectral signatures canthen be used along with processed acoustic signal data to detect and/orcharacterize an event at a depth range of interest by matching thedetected frequency domain features to the acoustic signature(s). Theevents can include various fluid and/or particulate flows (e.g., sand)and/or inflows as described herein. The spectral signatures can bedetermined by considering the different types of flow occurring within awellbore and characterizing the frequency domain features for each typeof flow. In some embodiments, various combinations and/ortransformations of the frequency domain features can be used tocharacterize each type of flow. Further, in some embodiments, thefrequency domain features may further be used to classify a flow rate ofeach identified type of flow.

For example, as schematically illustrated in FIG. 3, sand 202 can flowfrom the formation 102 into the wellbore 114 and then into the tubular120. As the sand 202 flows into the tubular 120, it can collide againstthe inner surface 204 of the tubular 120, and with the fiber 162 (e.g.,in cases where the fiber 162 is placed within the tubular 120), in arandom fashion. Without being limited by this or any particular theory,the intensity of the collisions depends on the effective mass and therate of change in the velocity of the impinging sand particles 202,which can depend on a number of factors including, without limitation,the direction of travel of the sand 202 in the wellbore 114 and/ortubular 120. The resulting random impacts can produce a random,broadband acoustic signal that can be captured on the optical fiber 162coupled (e.g., strapped) to the tubular 120. The random excitationresponse tends to have a broadband acoustic signal with excitationfrequencies extending up to the high frequency bands, for example, up toand beyond about 5 kHz depending on the size of the sand particles 202.In general, larger particle sizes may produce higher frequencies. Theintensity of the acoustic signal may be proportional to theconcentration of sand 202 generating the excitations such that anincreased broad band power intensity can be expected at increasing sand202 concentrations. In some embodiments, the resulting broadbandacoustic signals that can be identified can include frequencies in therange of about 5 Hz to about 10 kHz, frequencies in the range of about 5Hz to about 5 kHz or about 50 Hz to about 5 kHz, or frequencies in therange of about 500 Hz to about 5 kHz. Any frequency ranges between thelower frequencies values (e.g., 5 Hz, 50 Hz, 500 Hz, etc.) and the upperfrequency values (e.g., 10 kHz, 7 kHz, 5 kHz, etc.) can be used todefine the frequency range for a broadband acoustic signal.

The sand particles 202 entering the wellbore 114 can be carried within acarrier fluid 206, and the carrier fluid 206 can also generate highintensity acoustic background noise when entering the wellbore 114 dueto the turbulence associated with the fluid flowing into the tubular120. This background noise generated by the turbulent fluid flow isgenerally expected to be predominantly in a lower frequency region. Forexample, the fluid inflow acoustic signals can be between about 0 Hz andabout 500 Hz, or alternatively between about 0 Hz and about 200 Hz. Anincreased power intensity can be expected at low frequencies resultingfrom increased turbulence in the carrier fluid flow. The backgroundnoises can be detected as superimposed signals on the broad-bandacoustic signals produced by the sand 202 when the sand ingress occurs.

A number of acoustic signal sources can also be considered along withthe types of acoustic signals these sources generate. In general, avariety of signal sources can be considered including fluid flow with orwithout sand 202 through the formation 102, fluid flow with or withoutsand 202 through a gravel pack 122, fluid flow with or without sand 202within or through the tubular 120 and/or sand screen 118, fluid flowwith sand 202 within or through the tubular 120 and/or sand screen 118,fluid flow without sand 202 into the tubular 120 and/or sand screen 118,gas/liquid inflow, hydraulic fracturing, fluid leaks past restrictions(e.g., gas leaks, liquid leaks, etc.) mechanical instrumentation andgeophysical acoustic noises and potential point reflection noise withinthe fiber caused by cracks in the fiber optic cable/conduit underinvestigation.

For the flow of fluid 206, with the potential for sand 202 to be carriedwith the flowing fluid 206, in the formation 102, the likelihood thatany resulting acoustic signal would be captured by the optical fiber 162is considered low. Further, the resulting acoustic signal would likelybe dominated by low frequencies resulting from turbulent fluid flow.Similarly, the fluid flowing within the gravel pack 122 would likelyflow with a low flow speed and therefore limit the generation andintensity of any acoustic signals created by the sand 202. Thus, theacoustic response would be expected to occur in the lower frequencyrange.

For the flow of fluid 206 with or without sand 202 through a gravel pack122, the likelihood that any resulting acoustic signal would be capturedby the acoustic sensor is also considered low. Further, the resultingacoustic signal would likely be dominated by low frequencies resultingfrom turbulent fluid flow.

For the flow of fluid 206 with or without sand 202 within or through thetubular 120, the likelihood of capturing an acoustic signal isconsidered high due to the proximity of the source of the acousticsignals to the optical fiber 162 coupled to the tubular 120. This typeof flow can occur as the fluid 206 containing sand 202 flows within thetubular 120. Such flow would result in any sand flowing generallyparallel to the inner surface 204 of the tubular 120, which would limitthe generation of high frequency sounds as well as the intensity of anyhigh frequency sounds that are generated. It is expected that theacoustic signals generated from the flow of the fluid 206 through thetubular 120 and/or sand screen 118 may be dominated by low frequencyacoustic signals resulting from turbulent fluid flow.

In an embodiment, the acoustic signal due to fluid 206 containing sand202 within the tubular 120 can be expected to have a rise in acousticintensity from about 0 Hz to about 50 Hz, with a roll-off in powerbetween about 20 Hz to about 50 Hz.

For the flow of fluid 206 without any sand 202 into the tubular 120and/or sand screen 118, the proximity to the optical fiber 162 canresult in a high likelihood that any acoustic signals generated would bedetected by the acoustic sensor. As discussed herein, the flow of fluid206 alone without any sand 202 is expected to produce an acoustic signaldominated by low frequency signals due to the acoustic signals beingproduced by turbulent fluid flow.

For the flow of fluid 206 with sand 202 into the tubular 120 and/or sandscreen 118, the proximity to the optical fiber 162 can result in a highlikelihood that any acoustic signals generated would be detected by theoptical fiber 162. As further discussed herein, the flow of fluid 206with the sand 202 would likely result in an acoustic signal havingbroadband characteristics with excitation frequencies extending up tothe high frequency bands, for example, up to and beyond about 5 kHz.

Referring again to FIG. 1, the processor 168 within the acquisitiondevice 160 may be configured to perform various data processingprocesses to detect the presence of sand within a fluid flow along thelength of the wellbore 114 (more specifically along the length ofoptical fiber 162). For instance, the memory 170 may be configured tostore an application or program (e.g., comprising machine-readableinstructions, such as, for instance, non-transitory machine-readableinstructions) to perform the data analysis. While shown as beingcontained within the acquisition device 160, the memory 170 can compriseone or more memories, any of which can be external to the acquisitiondevice 160. In some embodiments, the processor 168 can execute theapplication, which can configure the processor 168 to filter theacoustic data set spatially, determine one or more frequency domainfeatures of the acoustic signal. In addition, in some embodiments theprocessor 168 (as a result of executing the application) may furtherdetermine whether or not sand is present within a fluid inflow or fluidflow at the selected location based on the analysis describedhereinbelow. The analysis can be repeated across various locations alongthe length of the wellbore 114 to determine the locations of sandingress, the makeup of a fluid carrying the sand (e.g., gas, water,hydrocarbon liquid, etc.), and the flow rate or amount of some or all ofthe fluid and/or the sand along the length of the wellbore 114.

Referring now to FIG. 4, a flow chart of a method 200 of determining anoperating envelope for a wellbore is shown. As described herein, thedescribed methods and related systems can be generally used to detectsand within a fluid flow. As used herein fluid flow can comprise fluidflow along or within a tubular within the wellbore such as fluid flowwithin a production tubular (e.g., production tubular 120 withinwellbore 114). Fluid flow can also comprise fluid flow from thereservoir or formation into a wellbore tubular and/or an annular spacebetween the wellbore tubular and the formation face. Such flow into thewellbore and/or a wellbore tubular can be referred to as fluid inflow.While fluid inflow may be separately identified at times in thisdisclosure, such fluid inflow is considered a part of fluid flow withinthe wellbore. In addition, as used herein “sand ingress,” refers to thesituation where a particulate and/or solid material (e.g., sand, gravel,solids, etc.) is entering into the wellbore from the subterraneanformation (e.g., such as within a fluid inflow), and “sand transport”refers to the situation where the particulate material is flowing alonga wellbore (e.g., such as within a fluid flow).

Generally speaking, method 200 may comprise producing one or more fluidsinto a wellbore at 201, obtaining an acoustic signal along the wellboreat 203, and determining one or a plurality of frequency domain featuresfrom the acoustic signal at 208, detecting a sand ingress and/or a sandtransport within the wellbore using the plurality of frequency domainfeatures at 216, correlating a force on a production face of thewellbore with the detected sand ingress and/or the detected sandtransport at 218, and determining an operating envelope for a force onthe production face of the wellbore based on the correlating at 220. Insome embodiments, the force on the production face of the wellbore anoptionally also be correlated with a production rate of one or morefluids. In some embodiments, method 200 includes identifying one or morefluid inflow locations at 212. In some embodiments, method 200 includesidentifying a sand ingress and/or transport within a flow at the one ormore fluid inflow locations using the plurality of frequency domainfeatures at 216. In some embodiments method 200 may comprisepreprocessing the acoustic signal at 205 prior to determining the one orthe plurality of frequency domain features from the acoustic signal at208. In addition, in some embodiments, method 200 may comprisenormalizing the one or the plurality of frequency domain features at 210and/or identifying the one or more fluid flow locations at 212 prior toidentifying sand within a flow at 216. The above noted features ofmethod 200 are now described in more detail below.

Initially, method 200 includes producing one or more fluids into awellbore at 201. Referring briefly again to FIG. 1 in addition to FIG.3, in some embodiments, producing the one or more fluids into thewellbore may comprise producing fluids into a wellbore 114 at one ormore production zones 104 a, 104 b and flowing the produced fluids intoand through a production tubular 120. As previously described above, thefluid produced at 201 may comprise a number of different components,such as, for instance, hydrocarbon liquids (e.g., oil), hydrocarbongases (e.g., ethane, methane, propane, etc.), aqueous fluids (e.g.,water, salt water, etc.). In addition, as was also previously mentionedabove, the one or more fluids produced into the wellbore at 201 mayinclude sand or other particulate matter produced from the formation102.

Referring again to FIG. 3, method 200 next includes obtaining anacoustic signal at 203. Such an acoustic signal can be obtained via anysuitable method. For instance, the acoustic signal may be obtainedutilizing a DAS system, such as, for instance the DAS system 110 shownin FIG. 1, in the manner previously described above.

After the acoustic signal is obtained at 203, method 200 may proceed, insome embodiments, to pre-process the raw data at 205. The acousticsignal can be generated within the wellbore as previously described.Depending on the type of DAS system employed (e.g., DAS system 110 inFIG. 1), the optical data may or may not be phase coherent and may bepre-processed to improve the signal quality (e.g., denoised foropto-electronic noise normalization/de-trending single point-reflectionnoise removal through the use of median filtering techniques or eventhrough the use of spatial moving average computations with averagingwindows set to the spatial resolution of the acquisition unit, etc.).The raw optical data from the acoustic sensor can be received,processed, and generated by the sensor to produce the acoustic signal.The data rate generated by various acoustic sensors such as the DASsystem can be large. For example, the DAS system may generate data onthe order of 0.5 to about 2 terabytes per hour. This raw data canoptionally be stored in a memory (e.g., memory 170 for DAS system 110 inFIG. 1).

A number of specific processing steps can be performed to determine thepresence of fluid inflow (or flow), and to detect a sand ingress or sandtransport within the detected fluid inflow (or flow). In someembodiments, a processor or collection of processors (e.g., processor168 in FIG. 1) may be utilized to perform the preprocessing stepsdescribed herein. In an embodiment, the noise detrended “acousticvariant” data can be subjected to an optional spatial filtering stepfollowing the other pre-processing steps, if present. A spatial samplepoint filter can be applied that uses a filter to obtain a portion ofthe acoustic signal corresponding to a desired depth or depth range inthe wellbore. Since the time the light pulse sent into the optical fiberreturns as backscattered light can correspond to the travel distance,and therefore depth in the wellbore, the acoustic data can be processedto obtain a sample indicative of the desired depth or depth range. Thismay allow a specific location within the wellbore to be isolated forfurther analysis. The pre-processing at 205 may also include removal ofspurious back reflection type noises at specific depths through spatialmedian filtering or spatial averaging techniques. This is an optionalstep and helps focus primarily on an interval of interest in thewellbore. For example, the spatial filtering step can be used to focuson a producing interval where there is high likelihood of sand ingress,for example. The resulting data set produced through the conversion ofthe raw optical data can be referred to as the acoustic sample data.

Filtering can provide several advantages. For instance, when theacoustic data set is spatially filtered, the resulting data, for examplethe acoustic sample data, used for the next step of the analysis can beindicative of an acoustic sample over a defined depth (e.g., the entirelength of the optical fiber, some portion thereof, or a point source inthe wellbore 114). In some embodiments, the acoustic data set cancomprise a plurality of acoustic samples resulting from the spatialfilter to provide data over a number of depth ranges. In someembodiments, the acoustic sample may contain acoustic data over a depthrange sufficient to capture multiple points of interest. In someembodiments, the acoustic sample data contains information over theentire frequency range of the detected acoustic signal at the depthrepresented by the sample. This is to say that the various filteringsteps, including the spatial filtering, do not remove the frequencyinformation from the acoustic sample data.

In some embodiments, the filtered data may be additionally transformedfrom the time domain into the frequency domain using a transform at 205(e.g., after it has been filtered—such as spatially filtered asdescribed above). For example, Discrete Fourier transformations (DFT) ora short time Fourier transform (STFT) of the acoustic variant timedomain data measured at each depth section along the fiber or a sectionthereof may be performed to provide the data from which the plurality offrequency domain features can be determined. The frequency domainfeatures can then be determined from the acoustic data. Spectral featureextraction using the frequency domain features through time and spacecan be used to determine the spectral conformance (e.g., whether or notone or more frequency domain features match or conform to certainsignature thresholds) and determine if an acoustic signature (e.g., asand ingress signature, a sand flow signature, etc.) is present in theacoustic sample. Within this process, various frequency domain featurescan be calculated for the acoustic sample data.

Preprocessing at 205 can optionally include a noise normalizationroutine to improve the signal quality. This step can vary depending onthe type of acquisition device used as well as the configuration of thelight source, the sensor, and the other processing routines. The orderof the aforementioned preprocessing steps can be varied, and any orderof the steps can be used.

Preprocessing at 205 can further comprise calibrating the acousticsignal. Calibrating the acoustic signal can comprise removing abackground signal from the acoustic signal, aligning the acoustic datawith physical depths in the wellbore, and/or correcting the acousticsignal for signal variations in the measured data. In some embodiments,calibrating the acoustic signal comprises identifying one or moreanomalies within the acoustic signal and removing one or more portionsof the acoustic signal outside the one or more anomalies.

Following the preprocessing at 205, method 200 may determine one or aplurality of frequency domain features from the acoustic signal at 208.The use of frequency domain features to identify inflow locations,inflow discrimination, sand ingress and/or transport detection (e.g.,within fluid inflow and/or fluid flow), and flow rate classification(e.g., for fluid inflow/flow and/or sand ingress/transport) can providea number of advantages. First, the use of frequency domain featuresresults in significant data reduction relative to the raw DAS datastream. Thus, a number of frequency domain features can be calculatedand used to allow for event identification while the remaining data canbe discarded or otherwise stored, and the remaining analysis canperformed using the frequency domain features. Even when the raw DASdata is stored, the remaining processing power is significantly reducedthrough the use of the frequency domain features rather than the rawacoustic data itself. Further, the use of the frequency domain featurescan, with the appropriate selection of one or more of the frequencydomain features, provide a concise, quantitative measure of the spectralcharacter or acoustic signature of specific sounds pertinent to downholefluid surveillance and other applications.

While a number of frequency domain features can be determined for theacoustic sample data, not every frequency domain feature may be used inthe identifying fluid flow characteristics, inflow locations, flow type,sand ingress/transport detection, or flow rate classification orprediction. The frequency domain features represent specific propertiesor characteristics of the acoustic signals. There are a number offactors that can affect the frequency domain feature selection for eachfluid inflow event. For example, a chosen descriptor should remainrelatively unaffected by the interfering influences from the environmentsuch as interfering noise from the electronics/optics, concurrentacoustic sounds, distortions in the transmission channel, and the like.In general, electronic/instrumentation noise is present in the acousticsignals captured on the DAS or any other electronic gauge, and it isusually an unwanted component that interferes with the signal. Thermalnoise is introduced during capturing and processing of signals byanalogue devices that form a part of the instrumentation (e.g.,electronic amplifiers and other analog circuitry). This is primarily dueto thermal motion of charge carriers. In digital systems additionalnoise may be introduced through sampling and quantization. The frequencydomain features should have values that are significant for a givenevent in the presence of noise.

As a further consideration in selecting the frequency domain feature(s)for a sand ingress or sand transport event in some embodiments, thedimensionality of the frequency domain feature should be compact. Acompact representation may be desired to decrease the computationalcomplexity of subsequent calculations. It may also be desirable for thefrequency domain feature to have discriminant power. For example, fordifferent types of audio signals, the selected set of descriptors shouldprovide altogether different values. A measure for the discriminantpower of a feature is the variance of the resulting feature vectors fora set of relevant input signals. Given different classes of similarsignals, a discriminatory descriptor should have low variance insideeach class and high variance over different classes. The frequencydomain feature should also be able to completely cover the range ofvalues of the property it describes.

In some embodiments, combinations of frequency domain features can beused. This can include an event signature (e.g., such as a sand ingresssignature or a sand transport signature, etc.) having multiple frequencydomain features as indicators. In some embodiments, a plurality offrequency domain features can be transformed to create values that canbe used to define various event signatures. This can includemathematical transformations including ratios, equations, rates ofchange, transforms (e.g., wavelets, Fourier transforms, other wave formtransforms, etc.), other features derived from the feature set, and/orthe like as well as the use of various equations that can define lines,surfaces, volumes, or multi-variable envelopes. The transformation canuse other measurements or values outside of the frequency domainfeatures as part of the transformation. For example, time domainfeatures, other acoustic features, and non-acoustic measurements canalso be used. In this type of analysis, time can also be considered as afactor in addition to the frequency domain features themselves. As anexample, a plurality of frequency domain features can be used to definea surface (e.g., a plane, a three-dimensional surface, etc.) in amultivariable space, and the measured frequency domain features can thenbe used to determine if the specific readings from an acoustic samplefall above or below the surface. The positioning of the readingsrelative to the surface can then be used to determine if the event ispresent or not at that location in that detected acoustic sample.

As an example, the chosen set of frequency domain features should beable to uniquely identify the event signatures with a reasonable degreeof certainty of each of the acoustic signals pertaining to a selecteddownhole surveillance application or fluid inflow event as describedherein. Such frequency domain features can include, but are not limitedto, the spectral centroid, the spectral spread, the spectral roll-off,the spectral skewness, the root mean square (RMS) band energy (or thenormalized sub-band energies/band energy ratios), a loudness or totalRMS energy, a spectral flatness, a spectral slope, a spectral kurtosis,a spectral flux, a spectral autocorrelation function, or a normalizedvariant thereof.

The spectral centroid denotes the “brightness” of the sound captured bythe optical fiber (e.g., optical fiber 162 shown in FIG. 1) andindicates the center of gravity of the frequency spectrum in theacoustic sample. The spectral centroid can be calculated as the weightedmean of the frequencies present in the signal, where the magnitudes ofthe frequencies present can be used as their weights in someembodiments.

The spectral spread is a measure of the shape of the spectrum and helpsmeasure how the spectrum is distributed around the spectral centroid. Inorder to compute the spectral spread, Si, one has to take the deviationof the spectrum from the computed centroid as per the following equation(all other terms defined above):

$\begin{matrix}{S_{i} = {\sqrt{\frac{\sum_{k = 1}^{N}{\left( {{f(k)} - C_{i}} \right)^{2}{X_{i}(k)}}}{\sum_{k = 1}^{N}{X_{i}(k)}}}.}} & \left( {{Eq}.\; 2} \right)\end{matrix}$

The spectral roll-off is a measure of the bandwidth of the audio signal.The Spectral roll-off of the i^(th) frame, is defined as the frequencybin ‘y’ below which the accumulated magnitudes of the short-time Fouriertransform reach a certain percentage value (usually between 85%-95%) ofthe overall sum of magnitudes of the spectrum.

$\begin{matrix}{{{\sum_{k = 1}^{y}\left| {X_{i}(k)} \right|} = \left. {\frac{c}{100}\sum_{k = 1}^{N}} \middle| {X_{i}(k)} \right|};} & \left( {{Eq}.\; 3} \right)\end{matrix}$

where c=85 or 95. The result of the spectral roll-off calculation is abin index and enables distinguishing acoustic events based on dominantenergy contributions in the frequency domain (e.g., between gas influxand liquid flow, etc.).

The spectral skewness measures the symmetry of the distribution of thespectral magnitude values around their arithmetic mean.

The RMS band energy provides a measure of the signal energy withindefined frequency bins that may then be used for signal amplitudepopulation. The selection of the bandwidths can be based on thecharacteristics of the captured acoustic signal. In some embodiments, asub-band energy ratio representing the ratio of the upper frequency inthe selected band to the lower frequency in the selected band can rangebetween about 1.5:1 to about 3:1. In some embodiments, the sub-bandenergy ratio can range from about 2.5:1 to about 1.8:1, or alternativelybe about 2:1 The total RMS energy of the acoustic waveform calculated inthe time domain can indicate the loudness of the acoustic signal. Insome embodiments, the total RMS energy can also be extracted from thetemporal domain after filtering the signal for noise.

The spectral flatness is a measure of the noisiness/tonality of anacoustic spectrum. It can be computed by the ratio of the geometric meanto the arithmetic mean of the energy spectrum value and may be used asan alternative approach to detect broad-banded signals. For tonalsignals, the spectral flatness can be close to 0 and for broader bandsignals it can be closer to 1.

The spectral slope provides a basic approximation of the spectrum shapeby a linearly regressed line. The spectral slope represents the decreaseof the spectral amplitudes from low to high frequencies (e.g., aspectral tilt). The slope, the y-intersection, and the max and mediaregression error may be used as features.

The spectral kurtosis provides a measure of the flatness of adistribution around the mean value.

The spectral flux is a measure of instantaneous changes in the magnitudeof a spectrum. It provides a measure of the frame-to-frame squareddifference of the spectral magnitude vector summed across allfrequencies or a selected portion of the spectrum. Signals with slowlyvarying (or nearly constant) spectral properties (e.g., noise) have alow spectral flux, while signals with abrupt spectral changes have ahigh spectral flux. The spectral flux can allow for a direct measure ofthe local spectral rate of change and consequently serves as an eventdetection scheme that could be used to pick up the onset of acousticevents that may then be further analyzed using the feature set above toidentify and uniquely classify the acoustic signal.

The spectral autocorrelation function provides a method in which thesignal is shifted, and for each signal shift (lag) the correlation orthe resemblance of the shifted signal with the original one is computed.This enables computation of the fundamental period by choosing the lag,for which the signal best resembles itself, for example, where theautocorrelation is maximized. This can be useful in exploratorysignature analysis/even for anomaly detection for well integritymonitoring across specific depths where well barrier elements to bemonitored are positioned.

Any of these frequency domain features, or any combination of thesefrequency domain features (including transformations of any of thefrequency domain features and combinations thereof), can be used todetect sand ingress and/or sand transport within the wellbore as well asto potentially determine the location, type, and flow rate of fluidinflow or fluid flow as described herein. In an embodiment, a selectedset of characteristics can be used to identify the presence or absencefor each event, and/or all of the frequency domain features that arecalculated can be used as a group in characterizing the presence orabsence of an event. The specific values for the frequency domainfeatures that are calculated can vary depending on the specificattributes of the acoustic signal acquisition system, such that theabsolute value of each frequency domain feature can change betweensystems. In some embodiments, the frequency domain features can becalculated for each event based on the system being used to capture theacoustic signal and/or the differences between systems can be taken intoaccount in determining the frequency domain feature values for eachfluid inflow event between or among the systems used to determine thevalues and the systems used to capture the acoustic signal beingevaluated.

One or a plurality of frequency domain features can be used to detect asand ingress or sand transport event and/or to quantify an amount (e.g.,flow rate) of sand associated with a sand ingress or sand transportevent (which may be referred to herein as a sand ingress rate or sandtransport rate, respectively). In some embodiments, one or a pluralityof frequency domain features can also be used to detect a sand ingressor sand transport event and/or to identify component rate or amountassociated with a sand ingress or sand transport event. In anembodiment, one, or at least two, three, four, five, six, seven, eight,etc. different frequency domain features can be used to detect a sandingress or transport and/or quantify a flow rate of sand associated withthe sand ingress or transport. The frequency domain features can becombined or transformed in order to define the event signatures for oneor more events, such as, for instance, a sand ingress signature toindicate sand flowing into a wellbore, and/or a sand transport signatureto indicate the transport or flowing of sand within and along thewellbore. While exemplary numerical ranges are provided herein, theactual numerical results may vary depending on the data acquisitionsystem and/or the values can be normalized or otherwise processed toprovide different results.

Referring still to FIG. 4, as previously described in some embodimentsmethod 200 may also comprise normalizing the one or the plurality offrequency domain features at 210 and/or then identifying the one or morefluid inflow locations at 212 prior to detecting a sand ingress and/or asand transport at 216. As shown in FIG. 3, in some embodiments, method200 may proceed to identifying the one or more fluid inflow locations at212 without first normalizing the frequency domain features at 210. Theone or more fluid inflow locations at 212 may be determined via otherdata, knowledge or experience as known to those of having ordinaryskill. For instance, in some embodiments, the one or more fluid inflowlocations may be determined via PLS data at 212. In some embodiments,the one or more fluid inflow locations at 212 are determined asdescribed hereinbelow.

For example, in some embodiments, block 212 may comprise identifying theone or more fluid flow and/or inflow locations using one or more of thefrequency domain features to identify acoustic signals corresponding tothe flow and/or inflow, and correlating the depths of those signals withlocations within the wellbore. The one or more frequency domain featurescan comprise at least two different frequency domain features in someembodiments. In some embodiments, the one or more frequency domainfeatures utilized to determine the one or more fluid inflow locationscomprises at least one of a spectral centroid, a spectral spread, aspectral roll-off, a spectral skewness, an RMS band energy, a total RMSenergy, a spectral flatness, a spectral slope, a spectral kurtosis, aspectral flux, a spectral autocorrelation function, as well ascombinations, transformations, and/or normalized variant(s) thereof.

In some embodiments, block 212 of method 200 may comprise: identifying abackground fluid flow signature using the acoustic signal; and removingthe background fluid flow signature from the acoustic signal prior toidentifying the one or more fluid inflow locations. In some embodiments,identifying the one or more fluid inflow locations comprises identifyingone or more anomalies in the acoustic signal using the one or morefrequency domain features of the plurality of frequency domain features;and selecting the depth intervals of the one or more anomalies as theone or more inflow locations. When a portion of the signal is removed(e.g., a background fluid flow signature, etc.), the removed portion canalso be used as part of the event analysis. Thus, in some embodiments,identifying the one or more fluid inflow locations at block 212comprises: identifying a background fluid flow signature using theacoustic signal; and using the background fluid flow signature from theacoustic signal to identify an event such as one or more fluid flowevents.

Without being limited to this or any other theory, identifying one ormore fluid inflow locations at 212 may be useful for identifying thelocations within the wellbore that a sand ingress event may occur. Thus,further analysis to determine whether a sand ingress is occurring may befocused on these identified locations so as to potentially reduceprocessing power and data collection during operations.

Referring still to FIG. 4, in some embodiments, method 200 comprisesdetecting a sand ingress and/or a sand transport within the wellbore(e.g., an inflow and/or a fluid flow within a wellbore) using aplurality of frequency domain features at 216. In some embodiments,method 200 may progress to block 216 immediately following block 208 orfollowing blocks 210 and/or 212 as previously described above and shownin FIG. 4. Thus, in some embodiments block 216 may comprise detecting asand ingress and/or sand transport using the plurality of frequencydomain features at the previously identified one or more fluid inflowlocations from 212. In some embodiments, the plurality of frequencydomain features utilized at block 216 may comprise one more of thefrequency domain features described herein including combinations,variants (e.g., a normalized variant), and/or transformations thereof.For instance, in some embodiments, at least two such frequency domainfeatures (and/or combinations, variants, or transformations thereof) areutilized at block 216. In some embodiments, the frequency domainfeatures utilized within block 216 may comprise a ratio between at leasttwo of the plurality of the frequency domain features.

In some embodiments, block 216 of method 200 may comprise providing theplurality of frequency domain features to a sand detection model (e.g.,a logistic regression model) at 214 and detecting a sand ingress and/orsand transport within the wellbore based on the sand detection model. Insome embodiments, the sand detection model can be developed using and/ormay include machine learning such as a neural network, a Bayesiannetwork, a decision tree, a logistical regression model, or a normalizedlogistical regression, or other supervised learning models. In someembodiments, the model at 214 may define a relationship between at leasttwo of the plurality of the frequency domain features, including in someembodiments combinations, variations, and/or transformations of thefrequency domain features and the presence or occurrence of sand ingressand/or a sand transport. Thus, the sand detection model at block 214 maycomprise a multivariable model in which the two or more frequency domainfeatures are variables that may be provided by acoustic data (e.g., suchas acoustic data obtained from DAS system 110 as previously describedabove). Thus, the sand detection model may utilize one or more (e.g., atleast two) of the frequency domain features as inputs therein. In someembodiments, block 216 (e.g., including block 214) may compriseutilizing the plurality of frequency domain features at the identifiedone or more fluid inflow locations (e.g., such as at the productionzones 104 a, 104 b shown in FIG. 1) in the sand detection model and thencomparing the plurality of frequency domain features to an output of themodel(s); and detecting a sand ingress event based on the comparison(s).

The sand detection model at 214 may be configured to detect sandingresses and/or sand transports in different fluid phases, at differentsand amounts, in different orientations, and through different types ofproduction assemblies, pipes, annuli, and the like. In some embodiments,the sand detection model at 214 may be trained to detect the sandingress and/or sand transport events. Specifically, acoustic data from aknown fluid flow (e.g., one in which the presence and/or amount of sandtherein is known or otherwise determined) can be used in the sanddetection model development process to determine one or moremultivariate models indicative of the presence of sand in an inflowingfluid in one or more fluid phases and/or in a flowing fluid within thewellbore within one or more fluid phases. Such multivariate models maythen be used with detected acoustic data at 214 and 216 to determine ifa sand ingress and/or a sand transport is occurring within the wellbore.

In some embodiments, the sand detection model at 214 may define one ormore event signatures based on selected frequency domain features (orcombinations, transformations, or variants thereof). For instance, asand detection model may define a first event signature for sand ingressfrom one or more production zones (e.g., productions zones 104 a, 104 bin FIG. 1), and a second event signature for sand transport along thewellbore. In some embodiments, the sand detection model may define aplurality of sand ingress signatures for determining if sand is flowinginto the wellbore at multiple locations and/or under multiple fluid flowconditions. Similarly, the sand detection model may define a pluralityof sand transport signatures for determining if sand flowing or beingtransported within different portions of the wellbore. Thus, duringoperations, the frequency domain features from the obtained acousticsignal may be compared against the predetermined event signatures, and adetermination may be made that the particular event(s) are occurring ifthe selected frequency domain features substantially correspond with theevent signature (e.g., the frequency domain features or combinations,variants, transformations thereof are within a threshold range, aregreater than, equal to, or less than a predetermined decision threshold,etc. defined by the event signature, etc.).

In some embodiments, the sand detection model at 214 may not only beconfigured to detect the presence of a sand ingress and/or a sandtransport within the wellbore, but may also be configured to determineor detect an amount or flow rate of sand associated with the detectedsand ingress and/or sand transport. In some embodiments, a multivariablemodel (or a set of multivariable models) may then be utilized todetermine an amount, or production rate of the sand that is associatedwith a given (e.g., detected) sand ingress and/or sand transport event.In some embodiments, the multivariable model(s) may utilize a pluralityof frequency domain features (e.g., such as at least two frequencydomain features) as inputs to determine a production rate or amount ofthe sand. For instance, the multivariable model(s) may classify theproduction rate or amount of sand within the sand ingress and/or sandtransport into one or more predetermined ranges or buckets based on aplurality of decision boundaries that are dependents upon chosen sets orgroups of frequency domain features. Thus, by applying the obtainedacoustic data to the second multivariable model(s), one may determinewhether sand production falls within a plurality of predeterminedproduction rate ranges (e.g., such as a low, medium, and high rangehaving preselected production rate boundaries).

In some embodiments, the sand detection model at 214 may be configuredto determine or detect a sand ingress and/or sand transport event whenthe production rate or amount of sand within the particular event isabove a predetermined threshold (e.g., a sand ingress threshold, a sandtransport threshold, etc.). Thus, in these embodiments, themultivariable model at 214 may be constructed and trained so as to“detect” the sand ingress and/or sand transport when a production rateof the sand within the sand ingress and/or sand transport rises abovesome predetermined minimum value (e.g., such as a 5 million barrels perday—mbpd—in some embodiments). An operator may select the predeterminedminimum value based on the production characteristics of the well, thedesign of the production equipment (e.g., both within the wellbore andat the surface), etc. Thus, the predetermined minimum or threshold valueof sand may range greatly in various embodiments.

In some embodiments, the detection of the sand ingress and/or the sandtransport may occur while simultaneously producing one or more fluidsinto and/or from the wellbore (e.g., hydrocarbon liquids, water,hydrocarbon gas, etc.). The components and/or flow rates of the one ormore fluids may also be determined via a multivariable model which maybe substantially similar to the sand detection model described above. Inparticular, in some embodiments, one or more multivariable models (e.g.,logistic regression models) may utilize one or more frequency domainfeatures (as well as combinations, variants, and/or transformationsthereof) to detect a fluid inflow/flow, determine the one or more fluidswithin the fluid inflow/flow, and/or to classify the flow rates of thedetected fluids of the one or more fluids.

In addition, in some embodiments, the one or more fluids produced intoand/or from the wellbore may be detected and/or characterized via othermethods that do not employ the use of multivariable models havingfrequency domain features as inputs. For instance, in some embodiments,the detection and characterization (e.g., including fluid types and flowrates therefor) may be determined via analysis of fluids emitted fromthe wellbore at or near the surface.

Referring still to FIG. 4, after detecting a sand ingress and/or a sandtransport within wellbore at 216, method 200 proceeds to correlate aforce on a production face of the wellbore (e.g., such as a force on aproduction face of one or more of the production zones in the wellbore)with the detected sand ingress and/or the detected sand transport at218. As previously described, the force on the production face of thewellbore may be measured or characterized by at least one of a rate ofpressure change in the production zone (e.g., production zones 104 a,104 b in FIG. 1), a flux of the one or more fluids through theproduction face of the wellbore, or an acceleration of the one or morefluids between a reservoir and an interior of the wellbore at theproduction face of the wellbore. Thus, in some embodiments, thecorrelating at block 218 may comprise correlating one or more of theabove listed parameters as the force on the production face, to the sandingress and/or the sand transport. In some embodiments, the correlationat block 218 may comprise correlating a plurality of (i.e., two or more)of the above listed parameters to the production rate of the one or morefluids as well as the sand ingress and/or the sand transport. In someembodiments, the correlating at block 218 may comprise correlating oneor more of the above listed parameters as the force on the productionface, to the production rate of the one or more fluids in addition tothe sand ingress and/or the sand transport.

In some embodiments, the sand monitoring system can provide informationon the rate of sand ingress and/or sand transport along with fluid flowrates and phase information. For example, an acoustic monitoring systemcan be used to identify one or more fluid phases (e.g., a gas phase, ahydrocarbon phase, an aqueous phase) along with flow rate information.This information can also be correlated with the force on the productionface of the wellbore and/or the sand ingress and/or sand transportlocations to become part of the operating envelope.

In some embodiments, the force on the production face may be measured(e.g., particularly any one or more of the parameters listed above) witha pressure monitoring system comprising one or more pressure sensorsdisposed within the wellbore (e.g., such as pressure monitoring system130 in FIG. 1). For instance, each of the above listed parameters formeasuring the force on the production face may be determined, inferred,or directly measured at least partially through monitoring of a downholepressure (e.g., wellbore pressure, a production zone pressure, formationpressure, drawdown pressure, etc.) via a pressure monitoring system asdescribed herein.

A flux of the one or more fluids through the production face refers toan amount of fluid passing through an area defined by the productionface within the production zone per time period. The flux can bemeasured using flow rate measurements obtained from the DAS or othersensors along with known geometric parameters of the wellbore andproduction face. The flux provides a measure of the force on the face ofthe formation by relating the amount of fluid being drawn across theface over time. In general, a larger fluid flow across the face of theformation (and thus a high flux) per each unit of time correlates to alarger force on the production face of the wellbore. The rate of changeof the flux can also affect the amount of sand where a larger change inthe flux (e.g., a larger increase in the flux) can result in a higherrate of sanding.

Similarly, an acceleration of the one or more fluids between thereservoir and the interior of the wellbore can be measured using flowand/or pressure measurements within a production zone. The accelerationof the one or more fluids can be related to a force on the formationwall, which can affect the rate of sand ingress into the wellbore.

In some embodiments, the correlation at block 218 may comprisecorrelating the sand ingress and/or the sand transport as a sand ingressrate and/or a sand transport rate, respectively. In these embodiments,the sand ingress rate and/or the sand transport rate may be determinedvia the sand detection model in the manner previously described above.

In some embodiments, the correlating at block 218 may compriseconstructing a look up table and/or a mathematical relationship and/ormodel. In some embodiments, the correlating at block 218 may compriseconstructing a plurality of look up tables and/or a plurality ofmathematical relationships and/or models.

In addition, in some embodiments, the correlating at block 218 maycomprise constructing a sand prediction model that correlates the sandingress and/or the sand transport (including the sand ingress rateand/or the sand transport rate as described above) with the productionrate of the one or more fluids from the wellbore, and one or moreparameters listed above to characterize the force on the production faceof the production zone. In some embodiments, the sand prediction modelmay correlate the sand ingress and/or the sand transport with one ormore (or two or more) of the production rate of the one of more fluids,a rate of pressure change within the wellbore, a flux of the one or morefluids through the production face of the wellbore, an acceleration ofthe one more fluids between the reservoir and an interior of thewellbore at the production face of the wellbore, or one or moregeophysical properties of the reservoir (e.g., such as a production zonewithin the reservoir). Thus, the sand prediction model may receive input(at least partially) from the output of the sand detection modeldescribed above (e.g., such as the detected sand ingress and/or sandtransport events, and/or potentially the sand ingress rates and/or thesand transport rates).

In some embodiments, the sand prediction model can be developed usingand/or may include machine learning such as a neural network, a Bayesiannetwork, a decision tree, a logistical regression model, or a normalizedlogistical regression, or other supervised learning models. In someembodiments, the sand prediction model may predict a sand ingress and/orsand transport (including in some embodiments a sand ingress rate and/ora sand transport rate) based on a production rate of the one or morefluids from the production zone of the wellbore and the force on theproduction face as described above. In some embodiments, the sandprediction model may predict a sand ingress and/or a sand transport(including in some embodiments a sand ingress rate and/or a sandtransport rate) based on one or more geophysical properties of theproduction zone either in lieu of or in addition to the other parametersdescribed above. In some embodiments the one or more geophysicalfeatures may comprise porosity, permeability, a measure of consolidationof a formation material, a type of formation material, or anycombination or variant thereof.

After correlating the force on the production face of the wellbore andthe production rate of the one or more fluids with the sand ingressand/or sand transport at 218, method 200 proceeds to determine anoperating envelope for the force on the production face of the wellborebased on the correlating at 220. In some embodiments, the operatingenvelope may be defined by an upper limit which may define a maximumforce on the production face of the wellbore that does not also cause orresult in sand ingress or at least results in sand ingress below apredetermined threshold.

As previously described, the force on the production face of thewellbore may be measured or characterized one or more of a variety ofparameters, and thus the operating envelope may provide for minimum andmaximum values of one or more of these particular parameters duringproduction operations for the wellbore. For instance, in someembodiments, the force on the production face of the wellbore maycomprise a rate of pressure change within the production zone (e.g.,productions zones 104 a, 104 b in FIG. 1), which may be furthercharacterized by a rate of change for the drawdown pressure aspreviously described above. Without being limited to this or any othertheory, a rate of pressure change in the production zone of the well(and thus also a rate of drawdown pressure change) may drive the fluxand/or acceleration of fluids through the production zone of the wellduring production operations. Thus, as the rate of pressure changeincreases (particularly as the pressure in the wellbore is decreasedrelative to the pressure within the production zone), the flux andacceleration of the fluids within the production zone toward and intothe wellbore may increase so as to dislodge and fluidized greateramounts of sand within the production zone (e.g., production zones 104a, 104 b in FIG. 1) into the wellbore. Therefore, the operating envelopedetermined at 220 may provide range of values for the rate of change forthe production zone pressure and/or the drawdown pressure (or one ormore of the other values that may be used to characterize or representthe force on the production face as described herein) that may avoidsand ingress within the wellbore.

In some embodiments, a boundary, such as for instance an upper boundaryor limit, of the operating envelope may be a function of at least one ofan absolute wellbore pressure and/or a production rate of the one ofmore fluids from the production zone(s) (e.g., production zones 104 a,104 b in FIG. 1). As previously explained, both of these values arerelated to the previously listed parameters for measuring orcharacterizing the force on the production face of a production zone inthe wellbore, and thus, during operations, the operating envelopedetermined at block 220 may be utilized to determine boundaries orlimits for the absolute wellbore pressure and/or the production rate ofthe one or more fluids (e.g., hydrocarbon liquids, hydrocarbon gases,water, etc.).

In some embodiments, the upper limit of the operating envelope maycomprise a limit of the force on the production face of the wellbore,above which sand ingress and/or sand transport may occur (e.g., sandingress can occur above a threshold amount or rate). In someembodiments, the upper limit of the operating envelope may comprise alimit of the force on the production face of the wellbore, above whichthe sand ingress rate and/or sand transport may rise above apredetermined maximum threshold value may occur. For instance, awellbore operator may choose to allow or accept some amount or rate ofsand ingress and/or sand transport during operations. In someembodiments, an acceptable amount or rate of sand ingress or transportmay comprise producing substantially no sand into the wellbore (i.e., asand ingress rate and/or a sand transport rate of substantially zero);however, in other embodiments, an acceptable amount or rate of sand maycomprise an amount or rate of sand that may be passed through the flowpaths and/or production equipment of the wellbore without (or withoutsignificant, appreciable, or otherwise unacceptable) wear or damagethereto. Moreover, an acceptable amount or rate of sand (e.g., such as asand ingress rate or a sand transport rate) may comprise an amount orrate of sand that may be lifted or produced to the surface with theother one or more produced fluids (e.g., such that there is little to noaccumulation of sand within the wellbore overtime).

In some embodiments, the operating envelope may be defined by a lowerlimit which may define a minimum amount of production (that is an amountor rate of the one or more fluids described above) from the wellbore.The minimum amount of production from the wellbore may be defined byeconomics. Specifically, the minimum amount of production may comprise aminimum amount of produced fluids that may provide sufficient revenue tooffset a cost of maintaining and producing the wellbore. In someembodiments, the minimum amount of production may be a minimum amount ofproduction to prevent other problems or issues. For instance, theminimum amount of production may comprise a minimum amount or flow ratethat will sufficiently lift liquid (e.g., water) from the wellbore suchthat water loading of the wellbore may be prevented or at least delayed.

In some embodiments, the operating window may be determined at block 220utilizing the sand prediction model developed at 218. Thus, the sandprediction model may provide an operating envelope for the force on theproduction face (or operating envelopes for any one or more of the abovelisted parameters that may be used to measure or characterize the forceon the production face) that may provide an acceptable amount or rate ofsand ingress and/or sand transport from the wellbore (which may comprisesubstantially no sand ingress and/or transport as previously describedabove).

In some embodiments, a processor (e.g., processor 168 in FIG. 1) orother controller may be coupled to a choke valve or other pressureadjustment mechanism of the wellbore. Thus, during operations, theprocessor may automatically make adjustments to the position of thechoke so as to maintain the well within the operating envelope. Forinstance, if a well operator desires to increase a drawdown pressure ofthe well, the processor may automatically adjust the position of thechoke valve to achieve the desired drawdown pressure while maintainingthe rate of change within the operating envelope so as to avoid or atleast limit sand ingress from the production zones of the well.

In some embodiments, following the determination of the operatingenvelope at 220, method 200 may include updating or refining theoperating envelope based on subsequently acquired data or observations(e.g., such as subsequently acquired acoustic signals as previouslydescribed above). In particular, in some embodiments, following block220, the operating envelope may be updated by: detecting the sandingress, sand transport, or both over a second time interval and thencorrelating the detected sand ingress and/or sand transport along withthe production rate of fluids produced during the second time periodwith a force on the production face of the wellbore via the procedurespreviously described above (e.g., via blocks 201-218 in FIG. 4).Thereafter, the operating envelope may be updated or re-determinedentirely based on the newly performed correlating (e.g., based on sandingress/transport detection during the second time interval).

Thus, through use of method 200, a well operator may determine anoperating envelope for operating (e.g., producing from) a subterraneanwellbore while limiting or avoiding sand ingress. In some embodiments, awell operator may utilize the operating envelope to determine a drawdownpressure, a production rate of one or more fluids, and/or an absolutewellbore pressure (or other operational parameters) that will limit sandingress during operations. In many instances, a well operator may wishto operate the wellbore at a limit of the drawdown pressure, absolutewellbore pressure, production rate that is associated with an upperlimit of the operating envelope, so as to maximize potential productionfrom the well (e.g., the production of hydrocarbon liquids and/orgases). Accordingly, the operating envelope may facilitate a maximumamount of production from the wellbore while still avoiding theequipment damage and/or plugging that is typically associated with theproduction of sand.

In some embodiments, a well operator may wish to remove sand that mayhave accumulated within the wellbore so as to ensure enhanced productionoperations thereafter. In some embodiments, sand may have accumulatedwithin the wellbore due to temporary operation outside of the operatingenvelope (e.g., either intentionally or unintentionally), due to anunforeseeable or unpredictable influx of sand, etc. It is expected thatan absolute flow rate of fluids through the wellbore will serve toremove any sand accumulations. In order to raise the fluid flow rate, anoperator may increase the drawdown pressure (e.g., by decreasing thepressure within the wellbore relative to the formation pressure) toincrease the fluid flow rates. In some embodiments, the drawdownpressure can be raised within the operating envelope to a point at whicha sufficient fluid flow rate (e.g., a production rate) is reached toremove the accumulated sand. In some embodiments, the drawdown pressurecan be raised fast enough so as to raise the force on the productionface above the upper limit of the operating envelope. The relative rapidrise in the drawdown pressure may increase a fluid acceleration and/orflux through the production face and into the wellbore, so that anoverall flow rate of fluids through the wellbore may be increased. Theincrease in fluid flow rate (or production rate) through the wellboremay work to fluidize sand that has accumulated within the wellbore, andtherefore encourage the production of this previously accumulated sandto the surface. When the drawdown pressure is increased above the limitdefined by the operating envelope, additional sand may be produced fromthe formation (i.e., additional sand ingress may occur); however, anoverall amount of sand within the wellbore may be generally decreaseddue to producing the previously accumulated sand to the surface. Onceall or some desired portion of the previously accumulated sand has beenproduced out of the wellbore, the drawdown pressure may be returned to apoint that is within the operating envelope (e.g., by increasing thepressure within the wellbore relative to the formation pressure) so asto return the force on the production face of the well to within theoperating envelope and therefore limit or avoid further sand ingress aspreviously described above.

In some embodiments, different operating envelopes may be determined foreach production zone (e.g., production zones 104 a, 104 b) of awellbore. For instance, a first operating envelope may be determined fora first production zone of a wellbore, a second operating envelope maybe determined for a second production zone of the wellbore, and so on.The first, second, etc. operating envelopes may be determined in themanner described above for method 200, except that different sandprediction models and associated envelopes may be constructed (e.g., aspreviously described) for each production zone.

In some embodiments, an operating window and/or a sand prediction modeldeveloped for a first wellbore or one or more production zones thereinmay be utilized to determine an operating window for a second wellboreor one or more production zones therein. The second wellbore may be asecond wellbore extending through the same subterranean formation as thefirst wellbore, or may be a second wellbore that extends through adifferent, and possibly remote, subterranean formation from thesubterranean formation of the first wellbore. This may be advantageousas it may allow an operating envelope to be defined for a wellborewithout obtaining sand detection measurements from that particularwellbore (e.g., such as via the DAS system 110 of FIG. 1). Thus, asecond wellbore may be operated within an operating envelope so as tolimit sand ingress as previously described above. For instance,reference is now made to FIG. 5 which shows a method 300 of determiningan operating envelope for a second wellbore, based on predeterminedoperating envelopes from one or more first wellbores according to someembodiments.

Initially, method 300 includes determining operating envelopes for aforce on the production face of the production zone(s) of one or morefirst wellbores at 302. The operating envelopes may be selected so as tolimit sand ingress from the production zone into the one or more firstwellbores from the corresponding production zone(s). Thus, in someembodiments, the operating envelopes may be determined for theproduction zones of the one or more first wellbores by applying thesystems and methods (e.g., described above), such as, in particular thesand monitoring system 110 and the method 200. Accordingly, in someembodiments, the operating envelopes may be derived from sand predictionmodels for the production zone(s) of each of the one or more firstwellbores in the manner previously described above (see e.g., method 200in FIG. 4).

In some embodiments, an operating envelope may be determined for asingle production zone (e.g., production zones 104 a, 104 b) of a singlefirst wellbore at 302. In some embodiments, operating envelopes may bedetermined for production zone(s) (e.g., a single production zone ormultiple production zones) for a plurality of first wellbores. Theplurality of first wellbores may extend into a single reservoir, or someor all of the first wellbores may extend into different reservoirs.Thus, at block 302, operating envelopes (and sand predictions models)may be developed for one or a plurality of first wellbores (includingpotentially multiple production zones within each of the firstwellbores).

Referring still to FIG. 5, in addition to determining the operatingenvelopes (and sand prediction models) for the production zone(s) of theone or more first wellbores at 302, method 300 also includes obtainingone or more first geophysical properties for the production zone(s) ofeach of the one or more first wellbores at 304. The one or more firstgeophysical properties may include any suitable rock properties,reservoir properties, fluid properties, etc. associated with theproduction zone(s) of the one or more first wellbores. For instance, theone or more geophysical properties may include one or more of porosity,permeability, a measure of consolidation of a formation material, a typeof formation material, or any combination or variant thereof. The one ormore first geophysical properties may be obtained via any suitablemethod including, for example, direct measurement by sensors, testing(e.g., such as core sample testing), observation during production,drilling, completion, or other wellbore operations, etc.

The obtained one or more first geophysical properties may be associatedwith the production zone(s) of the one or more first wellbores as wellas the operating envelopes (and underlying sand prediction models)previously determined for the production zone(s) of the one or morefirst wellbores. As previously described above, in some embodiments thesand prediction models that were constructed to determine the operatingenvelopes of the production zone(s) of the one or more first wellboresmay utilize at least some of the one or more geophysical properties as avariable therein. Thus, in blocks 302, 304 the operating envelopes mayeach be associated with a corresponding set of the one or more firstgeophysical properties and vice versa. In embodiments where a pluralityof operating envelopes are determined for the production zone(s) of aplurality of first wellbores, a catalogue or matrix may be constructedwhereby the plurality of operating envelopes (including the underlyingplurality of sand prediction models) are indexed by the one or morefirst geophysical properties. Thus, by searching this catalogue based onone or more geophysical properties of interest, one may obtain one ormore operating envelopes (and/or sand prediction models) that correspondwith the search criteria.

Method 300 also includes obtaining one or more geophysical propertiesfrom the production zone(s) of a second wellbore (e.g., secondgeophysical properties, etc.). The second wellbore may be different fromeach of the one or more first wellbores. For instance, the secondwellbore may be a different wellbore extending into the same reservoiras at least one of the one or more first wellbores, or the secondwellbore may extend into a different reservoir than all of the one ormore first wellbores. As used herein, the first geophysical propertiesand the second geophysical properties can be the same properties throughthe values as defined by the first and second geophysical properties mayvary between the two wellbores. For example, the one or more secondgeophysical properties of the production zone(s) of the second wellboremay include any or all of the same geophysical properties describedabove for the one or more first geophysical properties, and may beobtained, derived, inferred, measured, etc. via any of the methodsdescribed above. It should be appreciated that the one or moregeophysical properties may be obtained prior to actually forming (e.g.,drilling) and/or completing the second wellbore.

Once the one or more second geophysical properties of the productionzone(s) of the second wellbore are obtained at 306, method 300 proceedsto correlate the one or more second geophysical properties to the one ormore first geophysical properties. For instance, in some embodiments,block 306 may comprise comparing the one or more second geophysicalproperties to the one or more first geophysical properties. Thecomparison may be made so as to determine whether the one or more secondgeophysical properties correspond with the one or more first geophysicalproperties. For instance, the comparison may comprise determiningwhether the one or more second geophysical properties are within apredetermined range (e.g., +/−20%, +/−10%, +/−5%, +/−1%, etc.) of theone or more first geophysical properties. In embodiments where the oneor more first geophysical properties are obtained for a plurality offirst wellbores, the one or more second geophysical properties may becompared against some or all of the sets of the one or more firstgeophysical properties for each of the one or more first wellbores so asto determine which (if any) of the sets of one or more first geophysicalproperties corresponds (or best corresponds) to the one or more secondgeophysical properties according to previously determined criteria(e.g., such as that previously described).

Once the one or more second geophysical properties are correlated to theone or more first geophysical properties at 308, method 300 proceeds todetermine an operating envelope for the production zone(s) of the secondwellbore based on an operating envelope of the production zone(s) of aone of the one or more first wellbores having the one or more firstgeophysical properties that correspond with the one or more secondgeophysical properties at 310. In particular, block 310 may compriseapplying the operating envelope (and potentially the sand predictionmodel utilized to originally derive the operating envelope) of theproduction zone(s) of a particular one of the one or more firstwellbores that has one or more first geophysical properties thatcorrespond (e.g., via the example criteria described above) with the oneor more second geophysical properties. Without being limited to this orany other theory, if the geophysical properties of two wellbores (orproduction zones within the two wellbores) correspond in the mannerdescribed above, it may be assumed that the behavior of the twowellbores (or at least the two production zones) may be the same or atleast comparable. Thus, an operating envelope for limiting sand ingressfor a first of the two corresponding wellbores may be applied to providean applicable operating envelope for the second of the two correspondingwellbores. In some embodiments, the operating envelope for the firstwellbore can be modified based on any differences in propertiesidentified in the second of the two wellbores, which can help to adjustfor differences between the wellbores.

For some embodiments where operating envelopes and one or more firstgeophysical properties are obtained for a plurality of first wellboresat blocks 302 and 304, respectively, blocks 308 and 310 may comprisesearching a database or catalogue of the operating envelopes (and sandprediction models) utilizing the obtained one or more second geophysicalproperties of the second wellbore, and returning a list of operatingenvelopes or a single operating envelope that is associated with the oneor more geophysical properties that correspond, based on predeterminedcriteria as explained above, to the provided one or more secondgeophysical properties.

In some embodiments, a different operating envelope may be defined forsome or all of the production zones of the second wellbore at block 310.Each operating envelope may be determined based on an operating envelopeof a production zone of one of the first wellbores in which the one ormore first geophysical properties correspond with the one or more secondgeophysical properties of the particular production zone of the secondwellbore. Thus, in some embodiments the operating envelopes of at leastsome of the production zones of the second wellbore may be defined byoperating envelopes from different ones of the first wellbores.

Referring still to FIG. 5, method 300 also includes assessing a force ona production face of the production zone(s) of the second wellbore whileproducing fluids therefrom at 312. As previously described, the force onthe production face of a production zone may be measured orcharacterized by a number of different parameters. As is also describedabove, many (or all) of the above described parameters for measuringand/or characterizing the force on the production face of a productionzone may be determined, measured, inferred, etc. via a pressuremonitoring system including one or more pressure sensors disposed withinthe wellbore (e.g., such as pressure monitoring system 130 in FIG. 1).Therefore, at block 312, method may comprise taking one or more pressuremeasurements within the second wellbore via a suitable pressuremonitoring system to assess the force on the production face of theproduction zone(s) therein during production of one or more fluidstherefrom (e.g., hydrocarbons liquids, hydrocarbon gases, water, etc.).

After the operating envelope is defined at 310, method 300 also includesdetermining, using the defined operating envelope, a production rate forthe production zone(s) of the second wellbore that is less than or equalto a maximum production rate defined by the defined operating envelopeat 314. As previously described, a wellbore operating may wish tomaximize the production rate from a given well so as to produce as muchhydrocarbons (e.g., liquids and/or gases) therefrom as possible.However, producing a well at too high a production rate (or increasingthe production rate too quickly) can cause or increase sand ingress aspreviously described above. Therefore, by applying a maximum productionrate as defined by the operating envelope, a wellbore operating maymaximize production from the wellbore while limiting (including avoidingentirely) sand ingress.

Accordingly, method 300 also includes (in some embodiments), producingthe one or more fluids from the production zone(s) of the secondwellbore at the production rate at 316, and limiting sand ingress fromthe production zone(s) of the second wellbore to below a sand ingressthreshold or boundary as a result of producing the one or more fluids atthe production rate at 318. In some embodiments, the sand ingressthreshold may comprise a sand ingress rate (e.g., such as in mpbd). Insome embodiments, the sand ingress threshold may be substantially zero(such that substantially no sand ingress is occurring); however, in someembodiments, the sand ingress threshold may comprise a non-zero value(e.g., such as 5 mpbd in some embodiments). The sand ingress thresholdmay be predetermined (e.g., by the well operator), and may be determinedaccording to a variety of factors and considerations (e.g., theequipment disposed in the well, the propensity for the particularwellbore to experience plugging, the type of sand produced from theproduction zone(s), limitations of subterranean and surface equipment,etc.).

Accordingly, method 300 may be utilized to define operating envelope(s)for the production zone(s) of a second wellbore based on previouslydetermined operating envelopes for production zone(s) in one or morefirst wellbores as described above. Therefore, an operating envelope maybe determined for the production zone(s) of a second wellbore that doesnot have or employ a sand monitoring system (e.g., such as the DASsystem 110 in FIG. 1).

In some embodiments, one or more of the blocks of method 300 may becarried out before the second wellbore is fully formed (e.g., drilled,completed, etc.). For instance, any one or more of blocks 302-310 and314 may be performed prior to forming and/or completing second wellborein some embodiments. In addition, following the completion of method300, the defined operating window for the second wellbore may be updatedin a similar manner to that described above. For instance, additionalacoustic data may be obtained within the corresponding one of the one ormore first wellbores (e.g., the corresponding one of the one or morewellbores as described for block 308, 310), and the correspondingoperating envelope of the production zone(s) of the first wellbore maybe updated in substantially the same manner as described above withrespect to method 200 shown in FIG. 4. The updated operating envelope ofthe corresponding first wellbore may then be applied to the definedoperating envelope of the second wellbore in a similar manner so thatsubsequent changes in the production rate may be made according to theupdated envelope. In some embodiments, the additional acoustic data maybe obtained from a third wellbore. In some of these embodiments, it mayfirst be determined whether the production zone(s) of the third wellboresufficiently correspond to the production zone(s) of the second wellborein substantially the same manner as previously described above, prior toutilizing the acoustic data from the third wellbore to update theoperating envelope of the second wellbore.

In some embodiments, observed sand ingress from a production zone of awellbore may be higher than that predicted from the correspondingoperating envelope or sand prediction model. This may be true forwellbores that include a sand monitoring system (e.g., such as DASsystem 110 in FIG. 1) or for wellbores that do not include a sandmonitoring system (e.g., such as the “second wellbore” described abovein method 300 of FIG. 5). For wellbores with a sand monitoring system,the actual observed sand ingress may be determined via the sandmonitoring system and an associated sand detection model as describedabove. For wellbores that do not include a sand monitoring system, theactual observed sand ingress may be determined via other methods (e.g.,such as by analyzing fluids produced from the wellbore at the surface).In either case, if the observed actual sand ingress during productionfrom a wellbore is sufficiently different (e.g., greater) than apredicted sand ingress via the operating envelope (or associated sandprediction model), then the operating envelope and/or sand predictionmodel may be updated based on the actual observed sand ingress. In someembodiments, the operating envelope may be updated when the differencebetween observed sand ingress and the predicted sand ingress is greaterthan a predetermined sand variance threshold. The variance threshold mayrange in various embodiments, depending on a number of factors,including a maximum sand ingress rate that may be acceptable within theparticular wellbore. Without being limited to this or any other theory,by first determining whether and observe difference or variance betweenthe predicted and observed sand ingress rates is above a threshold,minor or less significant variances may not trigger an update to themodel so as to avoid unduly changing the operating envelope and/or sandprediction model during operations.

As previously described above, some of the blocks of method 300 in FIG.5 may be performed prior to forming and/or completing the secondwellbore. Thus, in some embodiments, a chosen operating envelope andassociated sand prediction model (e.g., from a corresponding firstwellbore as previously described above) may be utilized to influencevarious decisions and designs of the second wellbore. For instance, oncea corresponding operating envelope and sand prediction model areselected, the chosen operating envelope and associated sand predictionmodel may then be utilized to make predictions regarding future sandingress within the second wellbore (or at least a production zone of thesecond wellbore) so as to determine how or even whether to completevarious production zone(s) of the second wellbore. Reference is now madeto FIG. 6 which depicts a method 400 of completing a wellbore accordingto some embodiments disclosed herein.

Initially, method 400 includes receiving an indication of sand ingressat one or more production zones within a first wellbore at 402. In someembodiment, the indication of the sand ingress may be received ordetected utilizing a sand monitoring system and a sand detection modelin the manner previously described above for method 200. Thus, theindication of sand ingress may comprise acoustic data (and/or frequencydomain features derived from the acoustic data) from a DAS system (e.g.,DAS system 110 in FIG. 1), and a determination of the sand ingress maybe made by providing the obtained acoustic data to an appropriate sanddetection model in the manner previously described above.

Method 400 also includes receiving an indication of a force on theproduction face of the one or more production zones within the firstwellbore at 404. The force on the production face may be determined forthe production zone(s) within the first wellbore while one or morefluids are being produced from the production zone(s). As previouslydescribed above, the force on the production face may be measured orcharacterized by a number of different parameters (which are describedabove in more detail) and at least some of these parameters may bedetermined, measured, inferred, estimated, etc. from pressuremeasurements within the wellbore (e.g., such as wellbore pressure, apressure within the production zone(s), etc.). Thus, at block 404, theindication of the force on the production face may comprise one or morepressure readings from a pressure monitoring system (e.g., such aspressure monitoring system 300 shown in FIG. 1) as previously describedabove.

Next, method 400 includes determining one or more operating envelopesfor the one or more production zones in the first wellbore at 406. Aspreviously described above for methods 300 and 400, the operatingenvelopes may be selected so as to limit sand ingress from theproduction zone(s) into the first wellbore. Thus, in some embodiments,the operating envelopes may be determined for the one or more productionzones of the first wellbore by applying the systems and methodsdescribed above, such as, in particular the sand monitoring system 110and the method 200. Accordingly, in some embodiments, the operatingenvelopes may be derived from sand prediction models for each of the oneor more production zones of the first wellbore in the manner previouslydescribed above (see e.g., method 200 in FIG. 4).

Referring still to FIG. 6, method 400 also includes correlating one ormore production zones in a second wellbore with at least one or more ofthe production zones within the first wellbore at block 408. In someembodiments, the correlating at block 408 may comprise correlating oneor more geophysical properties (which may comprise any one or more ofthe geophysical properties previously described above) of the productionzone(s) of the second wellbore with one or more geophysical propertiesof the production zone(s) of the first wellbore. Thus, as is similarlydescribed for block 308 of method 300 in FIG. 5, block 408 may comprisecomparing the one or more geophysical properties of the productionzone(s) of the second wellbore to the one or more geophysical propertiesof the production zone(s) of the first wellbore, and this comparison maydetermine whether the one or more geophysical properties of theproduction zone(s) of the first and second wellbores are within apredetermined range (e.g., +/−20%, +/−10%, +/−5%, +/−1%, etc.) of oneanother.

In some embodiments, if the correlation of the geophysical features ofthe production zone(s) of the first and second wellbores yields adetermination that the production zone(s) of the second wellbore do notultimately correspond with the production zone(s) of the first wellbore(e.g., if the geophysical properties are not within the predefinedranges as described above), then method 400 may cease or blocks 402,404, 406 may be performed for a different first wellbore havingproduction zone(s) that do correspond with the production zone(s) of thesecond wellbore. If, conversely, the correlation of the geophysicalfeatures of the production zone(s) of the first and second wellboresyields a determination that the production zone(s) of the secondwellbore do correspond with the production zone(s) of the firstwellbore, then method may proceed to blocks 410-414 as described below.

In particular, following block 408, method 400 proceeds to define one ormore operating envelopes for the one or more production zones in thesecond wellbore based on the operating envelopes of the correlated oneor more production zones in the first wellbore at 410. Specifically,block 410 may comprise applying the operating envelope (and potentiallythe sand prediction model utilized to originally derive the operatingenvelope) of the production zone(s) of the first wellbore to theproduction zone(s) of the second wellbore that correspond therewith. Aspreviously described, the one or more production zones of the secondwellbore may correspond with the one or more production zones of thefirst wellbore when the geophysical properties of the respectiveproduction zones correspond with one another in the manner describedabove. In some embodiments, the selected one or more operating envelopescan be modified to account for differences between the geophysicalproperties of the first wellbore and the second wellbore.

Next, method 400 includes predicting sand ingress at the one or moreproduction zones in the second wellbore using the one or more operatingenvelopes for the one or more production zones of the second wellbore at412. Specifically, the one or more operating envelopes (and thus theunderlying sand prediction models generating the operating envelopes)may correlate a force on the production face of the one or moreproduction zones to the production rate of one or more fluids and a sandingress (e.g., such as a sand ingress rate) as previously describedabove. Thus, utilizing operating envelopes (and underlying sandprediction model), predictions can be made as to whether sand ingressmay occur at the one or more production zones under certain operatingconditions (e.g., drawdown pressure, production rate, etc.). In somecircumstances, one or more of the operating conditions for a well may bedetermined by other factors so that operation within the operatingenvelope is not possible (or at least no feasible) in certain scenarios.In some embodiments, the operating envelope generated by a sandprediction model may or shrink generally narrow over time as a result ofa pressure reduction in the production zone and/or the overallreservoir. Further, in some situations, a particular production zone maybe predisposed to produce sand regardless of the operating parametersapplied thereto. As a result, at times, operation of a wellbore may beoutside of the operating envelope such that sand ingress begins to occuror increases. However, the sand prediction model and/or the operatingenvelope may be used (e.g., at block 412) to predict the timing or eventhe severity of sand ingress for each of the one or more productionzones in the second well, so that early action (e.g., such asprophylactic action) may be taken by a well operator so as to minimizeor avoid the complications caused by the predicted sand ingress.

Therefore, at block 414, method 400 includes defining a completion planfor the second wellbore based on the predicted sand ingress at the oneor more production zones of the second wellbore. For example, in someembodiments the prediction at block 412 may comprise predicting sandwill ingress at a particular one or more of the production zones of thesecond wellbore for a given set of operating conditions. In some ofthese embodiments, the prediction at block 412 may comprise predicting asand ingress rate above a predetermined threshold from the one or moreproduction zones of the second wellbore. As a result, at block 414,method 400 may comprise defining a completion plan that includes placinga suitable sand screen, gravel packs, or other filtering device (e.g.,such as screen assemblies 118 and gravel packs 122 in FIG. 1) at the oneor more production zones of the second wellbore where sand ingress ispredicted in block 412. In addition, in some embodiments, the predictionat block 412 may including predicting that a sufficiently high sandingress rate is predicted for the expected operating conditions withinthe second wellbore that any production from these one or moreproduction zones may be uneconomical. Thus, the completion plan definedat block 414 may comprise not completing or placing a blank pipe atthese one or more production zones within the second wellbore. Further,in some embodiments, the prediction at block 412 may comprise predictingthat substantially no (or relatively little) sand ingress is expectedfor one or more of the production zones of the second wellbore, suchthat the completion plan defined at block 414 may comprise not insertinga sand screen, gravel pack, or other filter device at the one or moreproduction zones of the second wellbore.

In this regard, the completion plan provides a design or configurationfor a wellbore that is not yet drilled or has been drilled but has notyet been completed. The plan can define the physical configuration ofthe equipment placed within the wellbore, the type of equipment orcompletion to be used, and/or the equipment locations. The completionplan can also comprise an operating plan paired with the completion planto enable the drawdown of the new well to be improved or maximizedwithin a certain operating time frame.

The ability to use the model to predict future sanding based on certainoperating parameters can allow for a wellbore to be designed to improvethe overall amount of fluid produced from the wellbore in an economicalfashion. This can include avoiding the use of expensive completionequipment in some instances when the model indicates that certain zones,or in some embodiments entire wellbores, should not be completed inorder to avoid sand and/or undesirable fluid ingress (e.g., wateringress, etc.).

Thus, through performance of the method 400, sand ingress may bepredicted for a wellbore that does not include a sand monitoring system,and that may not even be formed (e.g., drilled) and/or completed. Thus,method 400 may allow a completion plan for the wellbore to be determinedso as to limit and/or avoid the predicted sand ingresses. Thus, theeconomic return for the wellbore may be more readily and predictablyachieved.

Any of the systems and methods disclosed herein can be carried out on acomputer or other device comprising a processor (e.g., a desktopcomputer, a laptop computer, a tablet, a server, a smartphone, or somecombination thereof), such as the acquisition device 160 of FIG. 2. FIG.7 illustrates a computer system 780 suitable for implementing one ormore embodiments disclosed herein such as the acquisition device or anyportion thereof. The computer system 780 includes a processor 782 (whichmay be referred to as a central processor unit or CPU) that is incommunication with memory devices including secondary storage 784, readonly memory (ROM) 786, random access memory (RAM) 788, input/output(I/O) devices 790, and network connectivity devices 792. The processor782 may be implemented as one or more CPU chips.

It is understood that by programming and/or loading executableinstructions onto the computer system 780, at least one of the CPU 782,the RAM 788, and the ROM 786 are changed, transforming the computersystem 780 in part into a particular machine or apparatus having thenovel functionality taught by the present disclosure. It is fundamentalto the electrical engineering and software engineering arts thatfunctionality that can be implemented by loading executable softwareinto a computer can be converted to a hardware implementation bywell-known design rules. Decisions between implementing a concept insoftware versus hardware typically hinge on considerations of stabilityof the design and numbers of units to be produced rather than any issuesinvolved in translating from the software domain to the hardware domain.Generally, a design that is still subject to frequent change may bepreferred to be implemented in software, because re-spinning a hardwareimplementation is more expensive than re-spinning a software design.Generally, a design that is stable that will be produced in large volumemay be preferred to be implemented in hardware, for example in anapplication specific integrated circuit (ASIC), because for largeproduction runs the hardware implementation may be less expensive thanthe software implementation. Often a design may be developed and testedin a software form and later transformed, by well-known design rules, toan equivalent hardware implementation in an application specificintegrated circuit that hardwires the instructions of the software. Inthe same manner as a machine controlled by a new ASIC is a particularmachine or apparatus, likewise a computer that has been programmedand/or loaded with executable instructions may be viewed as a particularmachine or apparatus.

Additionally, after the system 780 is turned on or booted, the CPU 782may execute a computer program or application. For example, the CPU 782may execute software or firmware stored in the ROM 786 or stored in theRAM 788. In some cases, on boot and/or when the application isinitiated, the CPU 782 may copy the application or portions of theapplication from the secondary storage 784 to the RAM 788 or to memoryspace within the CPU 782 itself, and the CPU 782 may then executeinstructions of which the application is comprised. In some cases, theCPU 782 may copy the application or portions of the application frommemory accessed via the network connectivity devices 792 or via the I/Odevices 790 to the RAM 788 or to memory space within the CPU 782, andthe CPU 782 may then execute instructions of which the application iscomprised. During execution, an application may load instructions intothe CPU 782, for example load some of the instructions of theapplication into a cache of the CPU 782. In some contexts, anapplication that is executed may be said to configure the CPU 782 to dosomething, e.g., to configure the CPU 782 to perform the function orfunctions promoted by the subject application. When the CPU 782 isconfigured in this way by the application, the CPU 782 becomes aspecific purpose computer or a specific purpose machine.

The secondary storage 784 is typically comprised of one or more diskdrives or tape drives and is used for non-volatile storage of data andas an over-flow data storage device if RAM 788 is not large enough tohold all working data. Secondary storage 784 may be used to storeprograms which are loaded into RAM 788 when such programs are selectedfor execution. The ROM 786 is used to store instructions and perhapsdata which are read during program execution. ROM 786 is a non-volatilememory device which typically has a small memory capacity relative tothe larger memory capacity of secondary storage 784. The RAM 788 is usedto store volatile data and perhaps to store instructions. Access to bothROM 786 and RAM 788 is typically faster than to secondary storage 784.The secondary storage 784, the RAM 788, and/or the ROM 786 may bereferred to in some contexts as computer readable storage media and/ornon-transitory computer readable media.

I/O devices 790 may include printers, video monitors, electronicdisplays (e.g., liquid crystal displays (LCDs), plasma displays, organiclight emitting diode displays (OLED), touch sensitive displays, etc.),keyboards, keypads, switches, dials, mice, track balls, voicerecognizers, card readers, paper tape readers, or other well-known inputdevices.

The network connectivity devices 792 may take the form of modems, modembanks, Ethernet cards, universal serial bus (USB) interface cards,serial interfaces, token ring cards, fiber distributed data interface(FDDI) cards, wireless local area network (WLAN) cards, radiotransceiver cards that promote radio communications using protocols suchas code division multiple access (CDMA), global system for mobilecommunications (GSM), long-term evolution (LTE), worldwideinteroperability for microwave access (WiMAX), near field communications(NFC), radio frequency identity (RFID), and/or other air interfaceprotocol radio transceiver cards, and other well-known network devices.These network connectivity devices 792 may enable the processor 782 tocommunicate with the Internet or one or more intranets. With such anetwork connection, it is contemplated that the processor 782 mightreceive information from the network, or might output information to thenetwork (e.g., to an event database) in the course of performing theabove-described method steps. Such information, which is oftenrepresented as a sequence of instructions to be executed using processor782, may be received from and outputted to the network, for example, inthe form of a computer data signal embodied in a carrier wave.

Such information, which may include data or instructions to be executedusing processor 782 for example, may be received from and outputted tothe network, for example, in the form of a computer data baseband signalor signal embodied in a carrier wave. The baseband signal or signalembedded in the carrier wave, or other types of signals currently usedor hereafter developed, may be generated according to several knownmethods. The baseband signal and/or signal embedded in the carrier wavemay be referred to in some contexts as a transitory signal.

The processor 782 executes instructions, codes, computer programs,scripts which it accesses from hard disk, floppy disk, optical disk(these various disk based systems may all be considered secondarystorage 784), flash drive, ROM 786, RAM 788, or the network connectivitydevices 792. While only one processor 782 is shown, multiple processorsmay be present. Thus, while instructions may be discussed as executed bya processor, the instructions may be executed simultaneously, serially,or otherwise executed by one or multiple processors. Instructions,codes, computer programs, scripts, and/or data that may be accessed fromthe secondary storage 784, for example, hard drives, floppy disks,optical disks, and/or other device, the ROM 786, and/or the RAM 788 maybe referred to in some contexts as non-transitory instructions and/ornon-transitory information.

In an embodiment, the computer system 780 may comprise two or morecomputers in communication with each other that collaborate to perform atask. For example, but not by way of limitation, an application may bepartitioned in such a way as to permit concurrent and/or parallelprocessing of the instructions of the application. Alternatively, thedata processed by the application may be partitioned in such a way as topermit concurrent and/or parallel processing of different portions of adata set by the two or more computers. In an embodiment, virtualizationsoftware may be employed by the computer system 780 to provide thefunctionality of a number of servers that is not directly bound to thenumber of computers in the computer system 780. For example,virtualization software may provide twenty virtual servers on fourphysical computers. In an embodiment, the functionality disclosed abovemay be provided by executing the application and/or applications in acloud computing environment. Cloud computing may comprise providingcomputing services via a network connection using dynamically scalablecomputing resources. Cloud computing may be supported, at least in part,by virtualization software. A cloud computing environment may beestablished by an enterprise and/or may be hired on an as-needed basisfrom a third party provider. Some cloud computing environments maycomprise cloud computing resources owned and operated by the enterpriseas well as cloud computing resources hired and/or leased from a thirdparty provider.

In an embodiment, some or all of the functionality disclosed above maybe provided as a computer program product. The computer program productmay comprise one or more computer readable storage medium havingcomputer usable program code embodied therein to implement thefunctionality disclosed above. The computer program product may comprisedata structures, executable instructions, and other computer usableprogram code. The computer program product may be embodied in removablecomputer storage media and/or non-removable computer storage media. Theremovable computer readable storage medium may comprise, withoutlimitation, a paper tape, a magnetic tape, magnetic disk, an opticaldisk, a solid state memory chip, for example analog magnetic tape,compact disk read only memory (CD-ROM) disks, floppy disks, jump drives,digital cards, multimedia cards, and others. The computer programproduct may be suitable for loading, by the computer system 780, atleast portions of the contents of the computer program product to thesecondary storage 784, to the ROM 786, to the RAM 788, and/or to othernon-volatile memory and volatile memory of the computer system 780. Theprocessor 782 may process the executable instructions and/or datastructures in part by directly accessing the computer program product,for example by reading from a CD-ROM disk inserted into a disk driveperipheral of the computer system 780. Alternatively, the processor 782may process the executable instructions and/or data structures byremotely accessing the computer program product, for example bydownloading the executable instructions and/or data structures from aremote server through the network connectivity devices 792. The computerprogram product may comprise instructions that promote the loadingand/or copying of data, data structures, files, and/or executableinstructions to the secondary storage 784, to the ROM 786, to the RAM788, and/or to other non-volatile memory and volatile memory of thecomputer system 780.

In some contexts, the secondary storage 784, the ROM 786, and the RAM788 may be referred to as a non-transitory computer readable medium or acomputer readable storage media. A dynamic RAM embodiment of the RAM788, likewise, may be referred to as a non-transitory computer readablemedium in that while the dynamic RAM receives electrical power and isoperated in accordance with its design, for example during a period oftime during which the computer system 780 is turned on and operational,the dynamic RAM stores information that is written to it. Similarly, theprocessor 782 may comprise an internal RAM, an internal ROM, a cachememory, and/or other internal non-transitory storage blocks, sections,or components that may be referred to in some contexts as non-transitorycomputer readable media or computer readable storage media.

Having described various systems and methods herein, specificembodiments can include those related to draw down of a well using anoperating envelope, draw down across wellbores, sand ingress predictionfor wellbores and across wellbores, and wellbore completion.

Various embodiments related to draw down of a well using an operatingenvelope can include, but are not limited to:

In a first embodiment, a method for determining an operating envelopefor a wellbore comprises: receiving an indication of sand ingress intothe wellbore from at least one production zone, sand transport along thewellbore, or both while producing one or more fluids from the wellborefrom the at least one production zone; correlating a force on aproduction face of the at least one production zone of the wellbore withthe sand ingress, the sand transport, or both; and determining anoperating envelope based on the correlating, wherein the operatingenvelope defines a boundary for the force on the production face of theat least one production zone of the wellbore during a production of theone or more fluids from the at least one production zone.

A second embodiment can include the method of the first embodiment,wherein the force on the production face of the at least one productionzone of the wellbore is further correlated with a production rate of theone or more fluids, and wherein the operating envelope is further basedon the correlation of the force on the production face of the at leastone production zone with the production rate of the one or more fluids.

A third embodiment can include the method of the first or secondembodiment, further comprising: detecting the sand ingress into thewellbore from the at least one production zone, the sand transport alongthe wellbore, or both using a sand monitoring system disposed within thewellbore.

A fourth embodiment can include the method of the third embodiment,wherein the sand monitoring system comprises an acoustic monitoringsystem.

A fifth embodiment can include the method of the third or fourthembodiment, wherein detecting the sand ingress, the sand transport, orboth using the sand monitoring system comprises: detecting an acousticsignal along the wellbore using a fiber optic cable disposed within thewellbore; comparing a sand ingress signature with the acoustic signal toproduce a first output; comparing a sand flow signature with theacoustic signal to produce a second output; and detecting the sandingress, the sand transport, or both based on the first output and thesecond output.

A sixth embodiment can include the method of any one of the third tofifth embodiments, further comprising controlling the production rate ofthe one or more fluids from the wellbore within the operating envelopebased on the detecting of the sand ingress from the at least oneproduction zone.

A seventh embodiment can include the method of the sixth embodiment,wherein controlling the production rate of the one or more fluids fromthe wellbore within the operating envelope comprises controlling theproduction rate of the one or more fluids without the use of the sandmonitoring system.

An eighth embodiment can include the method of any one of the third toseventh embodiments, further comprising detecting, with a pressuremonitoring system, a pressure within the wellbore while producing theone or more fluids and detecting the sand ingress, the sand transport,or both.

A ninth embodiment can include the method of the eighth embodiment,wherein the pressure monitoring system comprises a distributed pressuresensors system.

A tenth embodiment can include the method of the ninth embodiment,further comprising: monitoring a pressure in each of the at least oneproduction zones with the pressure monitoring system.

An eleventh embodiment can include the method of any one of the eighthto tenth embodiments, further comprising: detecting the sand ingress,sand transport, or both over a second time interval using the sandmonitoring system during production of the one or more fluids from thewellbore; detecting, with the pressure monitoring system, a pressurewithin the wellbore during the second time interval while producing theone or more fluids and detecting the sand ingress, the sand transport,or both; correlating the force on the production face of the at leastone production zone of the wellbore during the second time interval; andre-determining the operating envelope based on the correlating, whereinthe one or more fluids are produced within the re-determined operatingenvelope after the second time interval.

A twelfth embodiment can include the method of any one of the first toeleventh embodiments, wherein the force on the production face of the atleast one production zone of the wellbore is measured by at least one ofa rate of pressure change in the at least one production zone, a flux ofthe one or more fluids through the at least one production face of thewellbore, or an acceleration of the one or more fluids between areservoir and an interior of the wellbore at the production face of theat least one production zone.

A thirteenth embodiment can include the method of any one of the secondto twelfth embodiments, wherein the boundary for the force on theproduction face of the at least one production zone of the wellbore is afunction of at least one of an absolute pressure within the wellbore orthe production rate of the one or more fluids from the least oneproduction zone.

A fourteenth embodiment can include the method of any one of the firstto thirteenth embodiments, wherein the at least one production zonecomprises at least two production zones, and wherein the boundary forthe force on the production face of the wellbore is different betweenthe at least two production zones.

A fifteenth embodiment can include the method of any one of the first tofourteenth embodiments, further comprising: increasing the productionrate of the one or more fluids from the least one production zone whileremaining within the operating envelope.

A sixteenth embodiment can include the method of any one of the first tofifteenth embodiments, further comprising: automatically controlling theforce on the production face; and increasing the production rate of theone or more fluids in response to automatically controlling the force onthe production face.

A seventeenth embodiment can include the method of the fifteenth orsixteenth embodiment, wherein increasing the production rate of the oneor more fluids comprises producing the one or more fluids at a maximumproduction rate while remaining within the operating envelope.

An eighteenth embodiment can include the method of any one of thefifteenth to seventeenth embodiments, further comprising limiting sandaccumulation within the wellbore based on the increasing of theproduction rate of the one or more fluids while remaining within theoperating envelope.

A nineteenth embodiment can include the method of any one of the firstto eighteenth embodiments, further comprising: decrease a pressurewithin the wellbore to increase the force on the production face of theat least one production zone above the operating envelope; increasingthe production rate of the one or more fluids based on the decreasing ofthe pressure; removing at least a portion of sand accumulated within thewellbore based on the increase in the production rate; and increasingthe pressure after removing at least the portion of the sand accumulatedwithin the wellbore.

In a twentieth embodiment, a system for determining an operatingenvelope for a wellbore comprises: a monitoring assembly configured todetect one or more values related to the wellbore; a processor, whereinthe processor is configured to execute an analysis program to: receive,from the monitoring assembly, a sensor signal, wherein the sensor signalis generated while producing one or more fluids from at least oneproduction zone within the wellbore; detect sand ingress into thewellbore, sand transport along the wellbore, or both using the sensorsignal; correlate a force on a production face of the at least oneproduction zone of the wellbore with the sand ingress, the sandtransport, or both; and determine an operating envelope based on thecorrelating, wherein the operating envelope defines a boundary for theforce on the production face of the at least one production zone duringa production of the one or more fluids from the at least one productionzone.

A twenty first embodiment can include the system of the twentiethembodiment, wherein the processor is further configured to: correlatethe force on the production face of the at least one production zone ofthe wellbore with a production rate of the one or more fluids.

A twenty second embodiment can include the system of the twentieth ortwenty first embodiment, wherein the monitoring assembly comprises asand monitoring system disposed within the wellbore.

A twenty third embodiment can include the system of any one of thetwentieth to twenty second embodiments, wherein the sand monitoringsystem comprises: a fiber optic cable disposed in the wellbore; areceiver in signal communication with the fiber optical cable, whereinthe sensor signal comprises an acoustic signal, and wherein the receiveris configured to use a light pulse to detect an acoustic signal withinthe wellbore along the length of the fiber optic cable; wherein theprocessor is configured to detect the sand ingress, the sand transport,or both by executing the analysis program to: detect the acoustic signalusing the fiber optic cable disposed within the wellbore; compare a sandingress signature with the acoustic signal to produce a first output;compare a sand flow signature with the acoustic signal to produce asecond output; and detect the sand ingress, the sand transport, or bothbased on the first output and the second output.

A twenty fourth embodiment can include the system of any one of thetwentieth to twenty third embodiments, wherein the force on theproduction face of the at least one production zone is measured by atleast one of a rate of pressure change in the at least one productionzone, a flux of the one or more fluids through the production face of atleast one production zone, or an acceleration of the one or more fluidsbetween a reservoir and an interior of the wellbore at the productionface of the at least one production zone.

A twenty fifth embodiment can include the system of any one of thetwentieth to twenty fourth embodiments, wherein the boundary for theforce on the production face of the at least one production zone is afunction of at least one of an absolute pressure within the wellbore, ora production rate of the one or more fluids from the wellbore.

A twenty sixth embodiment can include the system of any one of thetwentieth to twenty fifth embodiments, wherein the monitoring assemblycomprises a pressure monitoring system configured to detect a pressurewithin the wellbore, wherein the processor is configured to execute theanalysis program to receive, from the pressure sensor, an indication ofthe pressure within the at least one production zone in the wellbore.

A twenty seventh embodiment can include the system of any one of thetwentieth to twenty sixth embodiments, wherein the processor is furtherconfigured to execute the analysis program to generate a control signalconfigured to increase the production rate of the one or more fluidswhile remaining within the operating envelope, wherein the increase inthe production rate limits sand accumulation within the wellbore.

A twenty eighth embodiment can include the system of the twenty seventhembodiment, wherein the processor is configured to execute the analysisprogram to generate the control signal automatically and automaticallycontrol the production rate of the one or more fluids.

A twenty ninth embodiment can include the system of any one of thetwentieth to twenty eighth embodiments, wherein the processor is furtherconfigured to execute the analysis program to: monitor and detect sandingress into the wellbore using the sensor signal during production fromthe wellbore; and control the production rate of the one or more fluidsfrom the wellbore within the operating envelope based on the detectionof the sand ingress from the at least one production zone.

A thirtieth embodiment can include the system of the twenty ninthembodiment, wherein the processor is configured to execute the analysisprogram to control the production rate of the one or more fluids at amaximum production rate of the one or more fluids within the operatingenvelope.

A thirty first embodiment can include the system of any one of thetwentieth to thirtieth embodiments, wherein the processor is furtherconfigured to execute the analysis program to generate a series ofcontrol signals configured to: decrease a pressure within the wellboreto increase the force on a production face of the at least oneproduction zone above the operating envelope, wherein the productionrate of the one or more fluids increases based on decreasing of thepressure, and wherein at least a portion of sand accumulated within thewellbore is removed based on the increase in the production rate; andincrease the pressure within the wellbore after at least the portion ofthe sand accumulated within the wellbore is removed.

In a thirty second embodiment, a method of controlling a drawdownpressure in a wellbore comprises: producing one or more fluids from awellbore at a first production rate; increasing a production of the oneor more fluids from the first production rate to a second productionrate, wherein the first production rate is less than the secondproduction rate, wherein the production rate increase is maintainedwithin an operating envelope, wherein the operating envelope defines aboundary for a rate of pressure change during a production of the one ormore fluids from the wellbore; and limiting sand ingress into thewellbore during the pressure increase based on maintaining the rate ofpressure change within the operating envelope.

A thirty third embodiment can include the method of the thirty secondembodiment, wherein the boundary for the rate of pressure change is afunction of an absolute pressure within the wellbore.

A thirty fourth embodiment can include the method of the thirty secondor thirty third embodiment, wherein the boundary for the rate ofpressure change is a function of the production rate of the one or morefluids from the wellbore.

A thirty fifth embodiment can include the method of any one of thethirty second to thirty fourth embodiments, wherein the operatingenvelope is determined by: detecting sand ingress into the wellbore froma production zone, sand transport along the wellbore, or both using anacoustic monitoring system disposed within the wellbore, wherein thedetecting of the sand ingress, the sand transport, or both occurs whileproducing the one or more fluids from the wellbore; detecting a pressurewithin the wellbore while producing the one or more fluids and detectingthe sand ingress, the sand transport, or both; correlating a rate ofpressure change with a production rate of the one or more fluids and thesand ingress, the sand transport, or both; and determining the operatingenvelope based on the correlating.

A thirty sixth embodiment can include the method of any one of thethirty second to thirty fifth embodiments, wherein the wellbore does notinclude an acoustic sensor while increasing the production of the one ormore fluids from the first production rate to the second productionrate.

Various embodiments related to draw down across wellbores can include,but are not limited to:

In a first embodiment, a method comprises: obtaining one or more firstgeophysical properties of a first production zone within a firstwellbore; correlating the one or more first geophysical properties witha set of geophysical properties having a corresponding set of determinedoperating envelopes; defining an operating envelope for the firstproduction zone based on the determined operating envelope of the set ofdetermined operating envelopes that corresponds to the first geophysicalproperties; determining, using the operating envelope, a force on aproduction face of the first production zone in the first wellbore thatis less than or equal to a maximum force on the production face of thefirst production zone defined by the operating envelope, wherein: theoperating envelope defines a boundary for a sand ingress rate inrelation to the force on the production face of the first productionzone during production of one or more fluids from the first productionzone, the force on the production face of the first production zone ismeasured by at least one of a rate of pressure change in the firstproduction zone, a flux of the one or more fluids through the productionface of the first production zone, or an acceleration of the one or morefluids between a reservoir and an interior of the first wellbore at theproduction face of the first production zone, and limiting sand ingressinto the first wellbore at the first production zone to below a sandingress threshold in response to producing the one or more fluids fromthe first production zone at the force on the production face.

A second embodiment can include the method of the first embodiment,further comprising: assessing the force on the production face of thefirst production zone during the production of one or more fluids,determining, using the operating envelope, a production rate for thefirst production zone in the first wellbore that is less than or equalto a maximum production rate defined by the operating envelope, whereinthe operating envelope further defines a boundary for the sand ingressrate in relation to the force on the production face of the firstproduction zone and the production rate within the first production zoneduring the production of the one or more fluids, and wherein the one ormore fluids are produced from the first production zone at theproduction rate.

A third embodiment can include the method of the second embodiment,wherein the operating envelope is determined by: receiving an indicationof sand ingress into a second production zone within a second wellbore,sand transport along the second wellbore, or both using a sandmonitoring system disposed within the second wellbore, wherein the sandingress, the sand transport, or both occurs while producing the one ormore fluids from the second wellbore from the second production zone;receiving one or more second geophysical properties of the secondproduction zone, wherein the second geophysical properties correspond tothe first geophysical properties of the first production zone; receivinga pressure within the second wellbore while producing the one or morefluids and detecting the sand ingress, the sand transport, or both;correlating a force on a production face of the second production zonewith a production rate of the one or more fluids and the sand ingress,the sand transport, or both; and determining the operating envelopebased on the correlating.

A fourth embodiment can include the method of the third embodiment,wherein receiving the indication of the sand ingress, the sandtransport, or both using the sand monitoring system comprises: receivingan acoustic signal originating along the second wellbore using a fiberoptic cable disposed within the second wellbore; comparing a sandingress signature with the acoustic signal to produce a first output;comparing a sand flow signature with the acoustic signal to produce asecond output; and determining the sand ingress, the sand transport, orboth based on the first output and the second output.

A fifth embodiment can include the method of any one of the first tofourth embodiments, wherein the boundary for the force on the productionface of the first production zone is a function of at least one of anabsolute pressure within the first production zone or the productionrate of the one or more fluids from the first production zone.

A sixth embodiment can include the method of any one of the second tofifth embodiments, wherein the production rate of the one or more fluidsis the maximum production rate defined by the operating envelope.

A seventh embodiment can include the method of any one of the first tosixth embodiments, wherein the first wellbore does not comprise a sandmonitoring system.

An eighth embodiment can include the method of any one of the first toseventh embodiments, further comprising: determining, using a pressuremonitoring system, a pressure within the second production zone of thesecond wellbore, wherein the pressure monitoring system comprises adistributed pressure sensors system.

A ninth embodiment can include the method of any one of the first toeighth embodiments, comprising: receiving the indication of the sandingress, sand transport, or both over a first time interval duringproduction of the one or more fluids from the second wellbore; receivinga pressure within the wellbore during the first time interval whileproducing the one or more fluids and detecting the sand ingress, thesand transport, or both; correlating the force on the production face ofthe second wellbore during the first time interval; and re-determiningthe operating envelope based on the correlating, wherein the one or morefluids are produced at a production rate within the re-determinedoperating envelope after the first time interval.

In a tenth embodiment, a system comprises: a processor; and a memorystoring an analysis program, wherein the processor is configured toexecute the analysis program to: receive one or more first geophysicalproperties of a first production zone within a first wellbore; correlatethe one or more first geophysical properties with a set of geophysicalproperties having corresponding set of determined operating envelopes;define an operating envelope for the first production zone based on thedetermined operating envelope of the set of determined operatingenvelopes that corresponds to the first geophysical properties;determine, using the operating envelope, a for a force on a productionface of the first production zone in the first wellbore that is lessthan or equal to a maximum force on the production face defined by theoperating envelope, wherein: the operating envelope defines a boundaryfor a sand ingress rate in relation to the force on the production faceof the first production zone during a production of one or more fluidsat a production rate, and the force on the production face of the firstproduction zone is measured by at least one of a rate of pressure changein the first production zone, a flux of the one or more fluids throughthe production face of the first production zone, or an acceleration ofthe one or more fluids between a reservoir and an interior of thewellbore at the production face of the wellbore; and generating anoutput with one or more parameters configured to allow the one or morefluids to be produced from the first production zone at the productionrate, wherein sand ingress into the wellbore at the first productionzone is limited to below a sand ingress threshold in response toproduction of the one or more fluids from the first production zone atthe production rate.

An eleventh embodiment can include the system of the tenth embodiment,wherein the processor is further configured to: asses the force on theproduction face of the first production zone during the production ofone or more fluids; determine, using the operating envelope, aproduction rate for the first production zone in the first wellbore thatis less than or equal to a maximum production rate defined by theoperating envelope, wherein the operating envelope further defines aboundary for the sand ingress rate in relation to the force on theproduction face of the first production zone and the production ratewithin the first production zone during the production of the one ormore fluids at the production rate.

A twelfth embodiment can include the system of the tenth or eleventhembodiment, further comprising: a sand monitoring system disposed withina second wellbore; and a pressure monitoring system configured to detecta pressure within the second wellbore, wherein the processor is furtherconfigured to execute the analysis program to: receive a signal from thesand monitoring system; detect, using the signal from the sandmonitoring system, sand ingress into a second production zone of thesecond wellbore, sand transport along the second wellbore, or both,wherein the detection of the sand ingress, the sand transport, or bothoccurs while one or more fluids are produced from the second productionzone, and wherein the second production zone has one or more secondgeophysical properties corresponding to the one or more firstgeophysical properties of the first production zone; receive a pressureoutput from the pressure monitoring system; detect, based on thepressure output, a pressure within the second production zone; correlatea force on a production face of the second production zone with aproduction rate of the one or more fluids from the second productionzone and the sand ingress, the sand transport, or both; and determinethe operating envelope based on the correlating.

A thirteenth embodiment can include the system of the twelfthembodiment, wherein the sand monitoring system comprises a fiber opticcable disposed within the second wellbore, where the signal from thesand monitoring system comprises an indication of an acoustic signalgenerated within the second wellbore.

A fourteenth embodiment can include the system of any one of the tenthto thirteenth embodiments, wherein the boundary for the force on theproduction face of the first production zone is a function of anabsolute pressure within the first production zone.

A fifteenth embodiment can include the system of any one of the tenth tofourteenth embodiments, wherein the boundary for the force on theproduction face of the first production zone is a function of theproduction rate of the one or more fluids from the first productionzone.

A sixteenth embodiment can include the system of any one of the tenth tofifthteenth embodiments, wherein the production rate of the one or morefluids is the maximum production rate defined by the operating envelope.

A seventeenth embodiment can include the system of any one of the tenthto sixteenth embodiments, wherein the first wellbore does not comprise asand monitoring system.

An eighteenth embodiment can include the system of any one of the tenthto seventeenth embodiments, further comprising: a pressure monitoringsystem configured to detect a pressure within the second wellbore,wherein the processor is further configured to execute the analysisprogram to: determine, based on a signal from the pressure monitoringsystem, a pressure within the second production zone, wherein thepressure monitoring system comprises a distributed pressure sensorssystem.

Various embodiments related to sand ingress prediction for wellbores andacross wellbores can include, but are not limited to:

In a first embodiment, a method of developing a predictive model forsand production from a wellbore comprises: receiving an indication ofsand ingress at one or more production zones within a first wellboreusing a sand monitoring system disposed within the first wellbore,wherein the sand ingress occurs while producing one or more fluids fromthe first wellbore; detecting, using a pressure monitoring system, apressure within the first wellbore while producing the one or morefluids and detecting the sand ingress; determining one or moregeophysical properties of the one or more production zones of the firstwellbore; and determining a model that correlates sand ingress at eachof the one or more production zones with a plurality of variables,wherein the plurality of variables include at least two of a productionrate of the one or more fluids from the first wellbore, a pressurewithin the first wellbore, a rate of change of the pressure within thefirst wellbore, a flux of the one or more fluids through the productionface of the wellbore, or an acceleration of the one or more fluidsbetween a reservoir and an interior of the wellbore at the productionface of the wellbore, or one or more of the geophysical properties ofthe first wellbore.

A second embodiment can include the method of the first embodiment,comprising: identifying a production zone in a second wellbore as beingone of the one or more production zones of the first wellbore; determinea pressure within the second wellbore and one or more geophysicalproperties of the production zone in the second wellbore; andpredicting, using the model, sand ingress within the production zone inthe second wellbore.

A third embodiment can include the method of the first or secondembodiment, wherein the one or more geophysical properties compriseporosity, permeability, a measure of a consolidation of a formationmaterial, a type of the formation material, or any combination thereof.

A fourth embodiment can include the method of any one of the first tothird embodiments, wherein the model is a logistical regression model.

A fifth embodiment can include the method of any one of the first tofourth embodiments, wherein the second wellbore extends within a samereservoir as the first wellbore.

A sixth embodiment can include the method of any one of the first tofifth embodiments, comprising controlling a production rate of the oneor more fluids from the second wellbore using the model.

A seventh embodiment can include the method of the sixth embodiment,wherein controlling the production rate of the one or more fluidscomprises producing the one or more fluids at a maximum production ratewhile remaining below a sand ingress threshold rate as predicted by themodel.

An eighth embodiment can include the method of any one of the first toseventh embodiments, wherein detecting the sand ingress at the one ormore productions zones within the first wellbore comprises: detecting anacoustic signal along the wellbore using the sand monitoring system,wherein the sand monitoring system comprises a fiber optic cabledisposed within the wellbore; comparing a sand ingress signature withthe acoustic signal at each of the one or more production zones; anddetecting the sand ingress at the one or more production zones withinthe first wellbore based on the comparison of the sand ingress signaturewith the acoustic signal.

A ninth embodiment can include the method of any one of the first toeighth embodiments, comprising: detecting sand ingress at one or moreproduction zones within a third wellbore using a second sand monitoringsystem disposed within the third wellbore; detecting, using a secondpressure monitoring system, a pressure within the third wellbore whileproducing the one or more fluids and detecting the sand ingress;determining one or more geophysical properties of the one or moreproduction zones of the third wellbore; updating the model based on thesand ingress, pressure, and one or more geophysical properties of thethird wellbore; and predicting, using the updated model, sand ingresswithin the production zone in the second wellbore.

A tenth embodiment can include the method of any one of the first toninth embodiments, comprising: detecting sand production from the secondwellbore; correlating the sand production from the second wellbore withthe predicted sand ingress in the second wellbore; and updating themodel when the sand production varies from the predicted sand ingress bymore than a variance threshold.

In an eleventh embodiment, a system for operating a wellbore comprises:a memory storing an analysis program; and a processor configured toexecute an analysis program to: receive, from a monitoring assembly, asensor signal, wherein the sensor signal is generated while producingone or more fluids from at least one production zone within a firstwellbore, wherein the monitoring assembly is configured to detect one ormore values related to the first wellbore, wherein the first wellborecomprises the at least one production zone capable of producing one ormore fluids; receive an indication of sand ingress into the firstwellbore using the sensor signal; receive one or more geophysicalproperties for the at least one production zone; and determine a modelthat correlates sand ingress at the at least one production zone with aplurality of variables, wherein the plurality of variables include atleast two of: a production rate of the one or more fluids from the firstwellbore, a pressure within the first wellbore, a rate of change of thepressure within the first wellbore, a flux of the one or more fluidsthrough the production face of the wellbore, or an acceleration of theone or more fluids between a reservoir and an interior of the wellboreat the production face of the wellbore, or the one or more of thegeophysical properties of the at least one production zone.

A twelfth embodiment can include the system of the eleventh embodiment,wherein the monitoring assembly comprises: a sand monitoring systemdisposed within a first wellbore; and a pressure monitoring systemconfigured to detect a pressure within the first wellbore.

A thirteenth embodiment can include the system of the eleventh ortwelfth embodiment, wherein the processor is further configured toexecute the analysis program to: receive pressure information and one ormore geophysical properties for a production zone in a second wellbore;and predict, using the model, sand ingress into the production zone inthe second wellbore based on the pressure information and the one ormore geophysical properties.

A fourteenth embodiment can include the system of the thirteenthembodiment, wherein the processor is further configured to execute theanalysis program to: receive production rate information for the secondwellbore, wherein the prediction of the sand ingress is further based onthe production rate information.

A fifteenth embodiment can include the system of the thirteenth orfourteenth embodiment, wherein the second wellbore extends into a samereservoir as the first wellbore.

A sixteenth embodiment can include the system of any one of the eleventhto fifteenth embodiments, wherein the model is a logistical regressionmodel.

A seventeenth embodiment can include the system of any one of thetwelfth to sixteenth embodiments, wherein the sand monitoring systemcomprises: a fiber optic cable disposed in the first wellbore; and areceiver in signal communication with the fiber optical cable, whereinthe sensor signal comprises an acoustic signal, and wherein the receiveris configured to use a light pulse to detect an acoustic signal withinthe wellbore along the length of the fiber optic cable; wherein theprocessor is configured to detect the sand ingress, the sand transport,or both by executing the analysis program to: detect the acoustic signalusing the fiber optic cable disposed within the wellbore; compare a sandingress signature with the acoustic signal to produce a first output;compare a sand flow signature with the acoustic signal to produce asecond output; and detect the sand ingress based on the first output andthe second output.

An eighteenth embodiment can include the system of any one of theeleventh to seventeenth embodiments, wherein the processor is furtherconfigured to execute the analysis program to: generate a control signalconfigured to increase a production rate of the one or more fluids;monitor the sand ingress into the first wellbore; and control theproduction rate of the one or more fluids while retaining the sandingress below a sand ingress threshold rate.

In a nineteenth embodiment, a method of predicting sand production froma wellbore comprises: detecting a production rate of one or more fluidsfrom at least one production zone within a first wellbore; detecting,using a pressure monitoring system, a pressure within the first wellborewhile producing the one or more fluids from at least one production zonewithin the first wellbore; determining one or more geophysicalproperties of the at least one production zone of the first wellbore;and predicting, using a sand prediction model, sand ingress within theat least one production zone in the first wellbore, wherein the sandprediction model correlates sand ingress at the at least one productionzone with a plurality of variables, wherein the plurality of variablesinclude at least two of: a production rate of the one or more fluidsfrom the first wellbore, a pressure within the first wellbore, a rate ofchange of the pressure within the first wellbore, a flux of the one ormore fluids through the production face of the at least one productionzone of the first wellbore, an acceleration of the one or more fluidsbetween a reservoir and an interior of the wellbore at the productionface of the at least one production zone of the first wellbore, or oneor more of the geophysical properties of the at least one productionzone of the first wellbore, and wherein the sand prediction model isbased on at least: sand ingress detected in a second wellbore having oneor more production zones, a detected pressure within the one or moreproduction zones of the second wellbore, and one or more geophysicalproperties of the second wellbore.

A twentieth embodiment can include the method of the nineteenthembodiment, comprising operating the first wellbore at or below amaximum production rate, wherein the maximum production rate is aproduction rate from at least one production zone within the firstwellbore at which the sand ingress is at or below a threshold sandingress rate.

A twenty first embodiment can include the method of the nineteenth ortwentieth embodiment, wherein the one or more geophysical propertiescomprise porosity, permeability, a measure of a consolidation of aformation material, a type of the formation material, or any combinationthereof.

A twenty second embodiment can include the method of any one of thenineteenth to twenty first embodiments, wherein the model is alogistical regression model.

A twenty third embodiment can include the method of any one of thenineteenth to twenty second embodiments, wherein the first wellboreextends into a same reservoir as the second wellbore.

A twenty fourth embodiment can include the method of any one of thenineteenth to twenty third embodiments, comprising controlling aproduction rate of the one or more fluids from the first wellbore usingthe sand prediction model.

A twenty fifth embodiment can include the method of the twenty fourthembodiment, wherein controlling the production rate of the one or morefluids comprises producing the one or more fluids at a maximumproduction rate while remaining below a sand ingress threshold rate aspredicted by the sand prediction model.

A twenty sixth embodiment can include the method of any one of thenineteenth to twenty fifth embodiments, comprising detecting, using asand monitoring system disposed in the first wellbore, sand ingresswithin the at least one production zone in the first wellbore.

A twenty seventh embodiment can include the method of the twenty sixthembodiment, wherein detecting the sand ingress comprises: detecting anacoustic signal along the first wellbore using the sand monitoringsystem, wherein the sand monitoring system comprises a fiber optic cabledisposed within the wellbore; comparing a sand ingress signature withthe acoustic signal at the at least one production zone; and detectingthe sand ingress at the at least one production zone within the firstwellbore based on the comparison of the sand ingress signature with theacoustic signal.

A twenty eighth embodiment can include the method of the twenty sixth ortwenty seventh embodiment, comprising: comparing the detected sandingress with the predicted sand ingress; and updating the sandprediction model when the detected sand ingress varies from thepredicted sand ingress exceeds a variance threshold.

Various embodiments related to wellbore completions can include, but arenot limited to:

In a first embodiment, a method of planning a wellbore completioncomprises: receiving an indication of sand ingress at one or moreproduction zones within a first wellbore; receiving an indication of aforce on a production face of the one or more production zones withinthe first wellbore; determining one or more operating envelopes for theone or more production zones in the first wellbore, wherein the one ormore operating envelopes define boundaries for a sand ingress rate inrelation to the force on the production face of the one or moreproduction zones during the production of one or more fluids from thecorresponding one or more production zones; correlating one or moreproduction zones in a second wellbore with at least one of the one ormore production zones within the first wellbore; defining one or moreoperating envelopes for the one or more production zones in the secondwellbore based on the correlated one or more production zones in thesecond wellbore with the at least one of the one or more productionzones within the first wellbore; predicting sand ingress at the one ormore production zones in the second wellbore using the one or moreoperating envelopes for the one or more production zones in the secondwellbore; and defining a completion plan for the second wellbore basedon the predicted sand ingress at the one or more production zones in thesecond wellbore.

A second embodiment can include the method of the first embodiment,wherein the one or more operating envelopes further define boundariesfor the sand ingress rate in relation to the force on the productionface of the one or more production zones and the production rate withineach of the one or more production zones during the production of one ormore fluids from the corresponding one or more production zones.

A third embodiment can include the method of the first or secondembodiment, wherein predicting sand ingress at the one or moreproduction zones in the second wellbore comprises predicting sandingress in a first of the one or more production zones; and wherein thecompletion plan for the second wellbore comprises determining that asand screen is to be placed at the first of the one or more productionzones as a result of predicting sand ingress.

A fourth embodiment can include the method of any one of the first tothird embodiments, wherein predicting sand ingress at the one or moreproduction zones in the second wellbore comprises predicting that therewill be substantially no sand ingress in a second of the one or moreproduction zones; and wherein the completion plan for the secondwellbore comprises determining that no sand screen is to be placed atthe second of the one or more production zones as a result of predictingsubstantially no sand ingress.

A fifth embodiment can include the method of any one of the first tofourth embodiments, wherein the completion plan defines a physicalconfiguration of completion equipment placed in the second wellbore.

A sixth embodiment can include the method of any one of the first tofifth embodiments, further comprising: completing the second wellboreusing the completion plan, wherein completing the second wellbore occursafter defining the completion plan.

A seventh embodiment can include the method of any one of the first tosixth embodiments, wherein the second wellbore is drilled after definingthe completion plan.

An eighth embodiment can include the method of any one of the first toseventh embodiments, wherein determining one or more operating envelopesfor the one or more production zones of the first wellbore comprises:receiving an indication of sand ingress into the first wellbore, sandtransport along the first wellbore, or both using a sand monitoringsystem disposed within the first wellbore, wherein the sand ingress, thesand transport, or both occurs while producing the one or more fluidsfrom the second wellbore from the second production zone; receiving apressure within the second wellbore while producing the one or morefluids and detecting the sand ingress, the sand transport, or both;correlating the force on a production face of the second wellbore withinthe second production zone with a production rate of the one or morefluids and the sand ingress, the sand transport, or both; anddetermining the one or more operating envelopes for the one or moreproduction zones based on the correlating.

A ninth embodiment can include the method of any one of the first toeighth embodiments, wherein correlating the one or more production zonesin the second wellbore with the at least one of the one or moreproduction zones within the first wellbore comprises: obtaining one ormore geophysical properties of the one or more production zones withinthe first wellbore; obtaining one or more geophysical properties of theone or more production zones within the second wellbore; and correlatingthe one or more geophysical properties of the one or more productionzones within the first wellbore with the one or more geophysicalproperties of the one or more production zones within the secondwellbore.

A tenth embodiment can include the method of the ninth embodiment,wherein the one or more geophysical properties comprise porosity,permeability, a measure of a consolidation of a formation material, atype of the formation material, or any combination thereof.

An eleventh embodiment can include the method of any one of the first totenth embodiments, further comprising: determining a model thatcorrelates sand ingress at each of the one or more production zoneswithin the first wellbore with a plurality of variables, wherein theplurality of variables include at least two of a production rate of theone or more fluids from the first wellbore, a pressure within the firstwellbore, a rate of change of the pressure within the first wellbore, aflux of the one or more fluids through the production face of thewellbore, or an acceleration of the one or more fluids between areservoir and an interior of the wellbore at the production face of thewellbore, or one or more of the geophysical properties of the firstwellbore; and wherein predicting the sand ingress at the one or moreproduction zones in the second wellbore further comprises using themodel to predict the sand ingress at the one or more production zones inthe second wellbore.

In a twelfth embodiment, a wellbore development system, the systemcomprises: a processor; and a memory storing an analysis program;wherein the processor is configured to execute an analysis program to:receive an indication of sand ingress at one or more production zoneswithin a first wellbore; receive an indication of a force on aproduction face of the one or more production zones within the firstwellbore; determine one or more operating envelopes for the one or moreproduction zones in the first wellbore, wherein the one or moreoperating envelopes define boundaries for a sand ingress rate inrelation to the force on the production face of the one or moreproduction zones during the production of one or more fluids from thecorresponding one or more production zones; correlate one or moreproduction zones in a second wellbore with at least one of the one ormore production zones within the first wellbore; define one or moreoperating envelopes for the one or more production zones in the secondwellbore based on the correlated one or more production zones in thesecond wellbore with the at least one of the one or more productionzones within the first wellbore; predict sand ingress at the one or moreproduction zones in the second wellbore using the one or more operatingenvelopes for the one or more production zones in the second wellbore;and define a completion plan for the second wellbore based on thepredicted sand ingress at the one or more production zones in the secondwellbore.

thirteenth embodiment can include the system of the twelfth embodiment,wherein the one or more operating envelopes further define boundariesfor the sand ingress rate in relation to the force on the productionface of the one or more production zones and the production rate withineach of the one or more production zones during the production of one ormore fluids from the corresponding one or more production zones.

A fourteenth embodiment can include the system of the twelfth orthirteenth embodiment, wherein the processor is further configured topredict sand ingress in a first of the one or more production zones,wherein the completion plan for the second wellbore indicates that asand screen is to be placed at the first of the one or more productionzones as a result of predicting sand ingress.

A fifteenth embodiment can include the system of any one of the twelfthto fourteenth embodiments, wherein the processor is further configuredto predict that there will be substantially no sand ingress in a secondof the one or more production zones, wherein the completion plan for thesecond wellbore indicates that no sand screen is to be placed at thesecond of the one or more production zones as a result of predictingsubstantially no sand ingress.

A sixteenth embodiment can include the system of any one of the twelfthto fifteenth embodiments, wherein the completion plan defines a physicalconfiguration of completion equipment placed in the second wellbore.

A seventeenth embodiment can include the system of any one of thetwelfth to sixteenth embodiments, wherein the second wellbore is notdrilled at the time the completion plan is defined.

An eighteenth embodiment can include the system of any one of thetwelfth to seventeenth embodiments, wherein the process is configuredto: receive an indication of sand ingress into the first wellbore, sandtransport along the first wellbore, or both from a sand monitoringsystem disposed within the first wellbore, wherein the sand ingress, thesand transport, or both occurs while producing the one or more fluidsfrom the second wellbore from the second production zone; receive apressure within the second wellbore while the one or more fluids areproduced and the sand ingress, the sand transport, or both are detected;correlate the force on a production face of the second wellbore withinthe second production zone with a production rate of the one or morefluids and the sand ingress, the sand transport, or both; and determinethe one or more operating envelopes for the one or more production zonesbased on the correlating.

A nineteenth embodiment can include the system of any one of the twelfthto eighteenth embodiments, wherein the processor is configured to:obtain one or more geophysical properties of the one or more productionzones within the first wellbore; obtain one or more geophysicalproperties of the one or more production zones within the secondwellbore; and correlate the one or more geophysical properties of theone or more production zones within the first wellbore with the one ormore geophysical properties of the one or more production zones withinthe second wellbore.

A twentieth embodiment can include the system of the nineteenthembodiment, wherein the one or more geophysical properties compriseporosity, permeability, a measure of a consolidation of a formationmaterial, a type of the formation material, or any combination thereof.

A twenty first embodiment can include the system of any one of thetwelfth to twentieth embodiments, wherein the processor is configuredto: determine a model that correlates sand ingress at each of the one ormore production zones within the first wellbore with a plurality ofvariables, wherein the plurality of variables include at least two of: aproduction rate of the one or more fluids from the first wellbore, apressure within the first wellbore, a rate of change of the pressurewithin the first wellbore, a flux of the one or more fluids through theproduction face of the wellbore, or an acceleration of the one or morefluids between a reservoir and an interior of the wellbore at theproduction face of the wellbore, or one or more of the geophysicalproperties of the first wellbore; and wherein the sand ingressprediction at the one or more production zones in the second wellborefurther uses the model to predict the sand ingress at the one or moreproduction zones in the second wellbore.

The embodiments disclosed herein have included systems and methods fordetecting and/or characterizing sand ingress and/or sand transportwithin a subterranean wellbore, or a plurality of such wellbores. Thus,through use of the systems and methods described herein, one may moreeffectively limit or avoid sand ingress and accumulation with a wellboreso as to enhance the economic production therefrom.

While exemplary embodiments have been shown and described, modificationsthereof can be made by one skilled in the art without departing from thescope or teachings herein. The embodiments described herein areexemplary only and are not limiting. Many variations and modificationsof the systems, apparatus, and processes described herein are possibleand are within the scope of the disclosure. Accordingly, the scope ofprotection is not limited to the embodiments described herein, but isonly limited by the claims that follow, the scope of which shall includeall equivalents of the subject matter of the claims. Unless expresslystated otherwise, the steps in a method claim may be performed in anyorder. The recitation of identifiers such as (a), (b), (c) or (1), (2),(3) before steps in a method claim are not intended to and do notspecify a particular order to the steps, but rather are used to simplifysubsequent reference to such steps.

What is claimed is:
 1. A method for determining an operating envelopefor a wellbore, the method comprising: receiving an indication of sandingress into the wellbore from at least one production zone, sandtransport along the wellbore, or both while producing one or more fluidsfrom the wellbore from the at least one production zone; correlating aforce on a production face of the at least one production zone of thewellbore with the sand ingress, the sand transport, or both, wherein theforce on the production face is measured by at least one of a rate ofpressure change in the at least one production zone, a flux of the oneor more fluids through the at least one production face of the wellbore,or an acceleration of the one or more fluids between a reservoir and aninterior of the wellbore at the production face of the at least oneproduction zone; and determining an operating envelope based on thecorrelating, wherein the operating envelope defines a boundary for theforce on the production face of the at least one production zone of thewellbore during a production of the one or more fluids from the at leastone production zone.
 2. The method of claim 1, wherein the force on theproduction face of the at least one production zone of the wellbore isfurther correlated with a production rate of the one or more fluids, andwherein the operating envelope is further based on the correlation ofthe force on the production face of the at least one production zonewith the production rate of the one or more fluids.
 3. The method ofclaim 1, further comprising: detecting the sand ingress into thewellbore from the at least one production zone, the sand transport alongthe wellbore, or both using a sand monitoring system disposed within thewellbore.
 4. The method of claim 3, wherein the sand monitoring systemcomprises an acoustic monitoring system, and wherein detecting the sandingress, the sand transport, or both using the sand monitoring systemcomprises: detecting an acoustic signal along the wellbore using a fiberoptic cable disposed within the wellbore; comparing a sand ingresssignature with the acoustic signal to produce a first output; comparinga sand flow signature with the acoustic signal to produce a secondoutput; and detecting the sand ingress, the sand transport, or bothbased on the first output and the second output.
 5. The method of claim3, further comprising controlling the production rate of the one or morefluids from the wellbore within the operating envelope based on thedetecting of the sand ingress from the at least one production zone. 6.The method of claim 6, wherein controlling the production rate of theone or more fluids from the wellbore within the operating envelopecomprises controlling the production rate of the one or more fluidswithout the use of the sand monitoring system.
 7. The method of claim 3,further comprising: detecting, with a pressure monitoring system, apressure within the wellbore while producing the one or more fluids anddetecting the sand ingress, the sand transport, or both.
 8. The methodof claim 7, wherein the pressure monitoring system comprises adistributed pressure sensors system, and wherein the method furthercomprises: monitoring a pressure in each of the at least one productionzones with the pressure monitoring system.
 9. The method of claim 7,further comprising: detecting the sand ingress, sand transport, or bothover a second time interval using the sand monitoring system duringproduction of the one or more fluids from the wellbore; detecting, withthe pressure monitoring system, a pressure within the wellbore duringthe second time interval while producing the one or more fluids anddetecting the sand ingress, the sand transport, or both; correlating theforce on the production face of the at least one production zone of thewellbore during the second time interval; and re-determining theoperating envelope based on the correlating, wherein the one or morefluids are produced within the re-determined operating envelope afterthe second time interval.
 10. The method of claim 2, wherein theboundary for the force on the production face of the at least oneproduction zone of the wellbore is a function of at least one of anabsolute pressure within the wellbore or the production rate of the oneor more fluids from the least one production zone.
 11. The method ofclaim 1, wherein the at least one production zone comprises at least twoproduction zones, and wherein the boundary for the force on theproduction face of the wellbore is different between the at least twoproduction zones.
 12. The method of claim 1, further comprising:increasing the production rate of the one or more fluids from the leastone production zone while remaining within the operating envelope; andlimiting sand accumulation within the wellbore based on the increasingof the production rate of the one or more fluids while remaining withinthe operating envelope.
 13. The method of claim 1, further comprising:automatically controlling the force on the production face; andincreasing the production rate of the one or more fluids in response toautomatically controlling the force on the production face.
 14. Themethod of claim 12, wherein increasing the production rate of the one ormore fluids comprises producing the one or more fluids at a maximumproduction rate while remaining within the operating envelope.
 15. Themethod of claim 1, further comprising: decrease a pressure within thewellbore to increase the force on the production face of the at leastone production zone above the operating envelope; increasing theproduction rate of the one or more fluids based on the decreasing of thepressure; removing at least a portion of sand accumulated within thewellbore based on the increase in the production rate; and increasingthe pressure after removing at least the portion of the sand accumulatedwithin the wellbore.
 16. A system for determining an operating envelopefor a wellbore, the system comprising: a monitoring assembly configuredto detect one or more values related to the wellbore; a processor,wherein the processor is configured to execute an analysis program to:receive, from the monitoring assembly, a sensor signal, wherein thesensor signal is generated while producing one or more fluids from atleast one production zone within the wellbore; receiving an indicationof sand ingress into the wellbore, sand transport along the wellbore, orboth using the sensor signal; correlate a force on a production face ofthe at least one production zone of the wellbore with the sand ingress,the sand transport, or both, wherein the force on the production face ofthe at least one production zone is measured by at least one of a rateof pressure change in the at least one production zone, a flux of theone or more fluids through the production face of at least oneproduction zone, or an acceleration of the one or more fluids between areservoir and an interior of the wellbore at the production face of theat least one production zone; and determine an operating envelope basedon the correlating, wherein the operating envelope defines a boundaryfor the force on the production face of the at least one production zoneduring a production of the one or more fluids from the at least oneproduction zone.
 17. The system of claim 16, wherein the processor isfurther configured to: correlate the force on the production face of theat least one production zone of the wellbore with a production rate ofthe one or more fluids.
 18. The system of claim 16, wherein themonitoring assembly comprises a sand monitoring system disposed withinthe wellbore.
 19. The system of claim 16, wherein the sand monitoringsystem comprises: a fiber optic cable disposed in the wellbore; areceiver in signal communication with the fiber optical cable, whereinthe sensor signal comprises an acoustic signal, and wherein the receiveris configured to use a light pulse to detect an acoustic signal withinthe wellbore along the length of the fiber optic cable; wherein theprocessor is configured to detect the sand ingress, the sand transport,or both by executing the analysis program to: detect the acoustic signalusing the fiber optic cable disposed within the wellbore; compare a sandingress signature with the acoustic signal to produce a first output;compare a sand flow signature with the acoustic signal to produce asecond output; and detect the sand ingress, the sand transport, or bothbased on the first output and the second output.
 20. The system of claim16, wherein the boundary for the force on the production face of the atleast one production zone is a function of at least one of an absolutepressure within the wellbore, or a production rate of the one or morefluids from the wellbore.
 21. The system of claim 16, wherein themonitoring assembly comprises a pressure monitoring system configured todetect a pressure within the wellbore, wherein the processor isconfigured to execute the analysis program to receive, from the pressuresensor, an indication of the pressure within the at least one productionzone in the wellbore.
 22. The system of claim 16, wherein the processoris further configured to execute the analysis program to generate acontrol signal configured to increase the production rate of the one ormore fluids while remaining within the operating envelope, wherein theincrease in the production rate limits sand accumulation within thewellbore.
 23. The system of claim 22, wherein the processor isconfigured to execute the analysis program to generate the controlsignal automatically and automatically control the production rate ofthe one or more fluids.
 24. The system of claim 16, wherein theprocessor is further configured to execute the analysis program to:monitor and detect sand ingress into the wellbore using the sensorsignal during production from the wellbore; and control the productionrate of the one or more fluids from the wellbore within the operatingenvelope based on the detection of the sand ingress from the at leastone production zone.
 25. The system of claim 24, wherein the processoris configured to execute the analysis program to control the productionrate of the one or more fluids at a maximum production rate of the oneor more fluids within the operating envelope.
 26. The system of claim16, wherein the processor is further configured to execute the analysisprogram to generate a series of control signals configured to: decreasea pressure within the wellbore to increase the force on a productionface of the at least one production zone above the operating envelope,wherein the production rate of the one or more fluids increases based ondecreasing of the pressure, and wherein at least a portion of sandaccumulated within the wellbore is removed based on the increase in theproduction rate; and increase the pressure within the wellbore after atleast the portion of the sand accumulated within the wellbore isremoved.
 27. A method of controlling a drawdown pressure in a wellbore,the method comprising: producing one or more fluids from a wellbore at afirst production rate; increasing a production of the one or more fluidsfrom the first production rate to a second production rate, wherein thefirst production rate is less than the second production rate, whereinthe production rate increase is maintained within an operating envelope,wherein the operating envelope defines a boundary for a rate of pressurechange during a production of the one or more fluids from the wellbore;and limiting sand ingress into the wellbore during the pressure increasebased on maintaining the rate of pressure change within the operatingenvelope.
 28. The method of claim 27, wherein the boundary for the rateof pressure change is a function of at least one of an absolute pressurewithin the wellbore, or the production rate of the one or more fluidsfrom the wellbore.
 29. The method of claim 27, wherein the operatingenvelope is determined by: detecting sand ingress into the wellbore froma production zone, sand transport along the wellbore, or both using anacoustic monitoring system disposed within the wellbore, wherein thedetecting of the sand ingress, the sand transport, or both occurs whileproducing the one or more fluids from the wellbore; detecting a pressurewithin the wellbore while producing the one or more fluids and detectingthe sand ingress, the sand transport, or both; correlating a rate ofpressure change with a production rate of the one or more fluids and thesand ingress, the sand transport, or both; and determining the operatingenvelope based on the correlating.
 30. The method of claim 27, whereinthe wellbore does not include an acoustic sensor while increasing theproduction of the one or more fluids from the first production rate tothe second production rate.